Edgar Filing: WILLIAMS COMPANIES INC

Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)



þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2016
	OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to

Commission file number 1-4174

The Williams Companies, Inc.

(Exact Name of Registrant as Specified in Its Charter)



Delaware		73-0569878
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

One Williams Center, Tulsa, Oklahoma		74172
(Address of Principal Executive Offices)		(Zip Code)

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, $1.00 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer þ	Accelerated filer ¨		Non-accelerated filer ¨	Smaller reporting company ¨
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second quarter was approximately $16,207,908,251.

The number of shares outstanding of the registrant’s common stock outstanding at February 17, 2017 was 825,823,918.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on May 18, 2017, are incorporated into Part III, as specifically set forth in Part III.

THE WILLIAMS COMPANIES, INC.

FORM 10-K

TABLE OF CONTENTS



		Page
PART I

Item 1.	Business	4
	Website Access to Reports and Other Information	4
	General	4
	Financial Repositioning	4
	Sale of Our Canadian Operations	5
	Energy Transfer Merger Agreement	5
	Organizational Realignment	5
	Financial Information About Segments	5
	Business Segments	5
	Williams Partners	6
	Williams NGL & Petchem Services	16
	Additional Business Segment Information	16
	Regulatory Matters	16
	Environmental Matters	19
	Competition	19
	Employees	20
	Financial Information about Geographic Areas	20
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	38
Item 2.	Properties	38
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	39
	Executive Officers of the Registrant	40

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	44
Item 6.	Selected Financial Data	45
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	76
Item 8.	Financial Statements and Supplementary Data	78
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	155
Item 9A.	Controls and Procedures	155
Item 9B.	Other Information	158

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	158
Item 11.	Executive Compensation	158
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	158
Item 13.	Certain Relationships and Related Transactions, and Director Independence	159
Item 14.	Principal Accountant Fees and Services	159

PART IV

Item 15.	Exhibits and Financial Statement Schedules	160

DEFINITIONS

The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Annual Report.

Measurements:

Barrel: One barrel of petroleum products that equals 42 U.S. gallons

Bcf : One billion cubic feet of natural gas

Bcf/d: One billion cubic feet of natural gas per day

British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree

Fahrenheit

Dekatherms (Dth): A unit of energy equal to one million British thermal units

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

MMdth: One million dekatherms or approximately one trillion British thermal units

MMdth/d: One million dekatherms per day

Tbtu: One trillion British thermal units

Consolidated Entities:

ACMP: Access Midstream Partners, L.P. prior to its merger with Pre-Merger WPZ

Cardinal: Cardinal Gas Services, L.L.C.

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

Jackalope: Jackalope Gas Gathering Services, L.L.C.

Northwest Pipeline: Northwest Pipeline LLC

Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP

Transco: Transcontinental Gas Pipe Line Company, LLC

WPZ: Williams Partners L.P.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of December 31, 2016, we account for as an equity-method investment, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Bluegrass: Bluegrass Pipeline Company LLC

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

Gulfstream: Gulfstream Natural Gas System, L.L.C.

Laurel Mountain: Laurel Mountain Midstream, LLC

Moss Lake: Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC

OPPL: Overland Pass Pipeline Company LLC

UEOM: Utica East Ohio Midstream LLC

Government and Regulatory:

EPA: Environmental Protection Agency

Exchange Act, the: Securities and Exchange Act of 1934, as amended

FERC: Federal Energy Regulatory Commission

GAAP: Generally accepted accounting principles

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

Other:

DRIP: Distribution reinvestment program

Energy Transfer: Energy Transfer Equity, L.P.

ETC: Energy Transfer Corp LP

ETC Merger: Merger wherein Williams would have been merged into ETC

Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,

such as ethane, propane, and butane

IDR: Incentive distribution right

LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures

Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its

affiliates

MVC: Minimum volume commitment

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are

used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation

PDH facility: Propane dehydrogenation facility

RGP Splitter: Refinery grade propylene splitter

Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility

PART I

Item 1. Business

In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to Williams as the “Company.”

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents electronically with the SEC under the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.

Our Internet website is www.williams.com. We make available, free of charge, through the Investor tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

GENERAL

We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to markets for natural gas, NGLs, and olefins. Our operations are located principally in the United States.

As of December 31, 2016, our interstate gas pipelines, midstream, and olefins production interests were largely held through our significant investment in Williams Partners L.P. (WPZ). We owned the general partner interest and a 58 percent limited-partner interest in WPZ. See the Financial Repositioning discussion below for recent changes to our interest in WPZ.

We were founded in 1908, originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. Williams’ headquarters are located in Tulsa, Oklahoma, with other major offices in Salt Lake City, Utah; Houston, Texas; Oklahoma City, Oklahoma; Pittsburgh, Pennsylvania; and the Four Corners Area. Our telephone number is 918-573-2000.

FINANCIAL REPOSITIONING

In January 2017, we announced agreements with WPZ, wherein we permanently waived the general partner’s incentive distribution rights and converted our 2 percent general partner interest in WPZ to a non-economic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 15 - Stockholders’ Equity of Notes to Consolidated Financial Statements). Following these transactions, we own a 74 percent limited partner interest in WPZ. It is anticipated that the combination of these measures will improve WPZ’s cost of capital, provide for debt reduction, and eliminate WPZ’s need to access the public equity markets for several years.

In addition to the previously announced Geismar monetization process, we have announced plans to monetize other select assets that are not core to our strategy. We expect to raise more than $2 billion in after-tax proceeds from the monetization process of Geismar and the other select assets.

SALE OF OUR CANADIAN OPERATIONS

In September 2016, we completed the sale of our Canadian operations. Consideration received to date totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. We recognized an impairment charge of $747 million during the second quarter of 2016 related to these operations and an additional loss of $66 million upon completion of the sale. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

ENERGY TRANSFER MERGER AGREEMENT

On September 28, 2015, we publicly announced in a press release that we had entered into a Merger Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, we would merge with and into the newly formed ETC, with ETC surviving the ETC Merger.

On June 29, 2016, Energy Transfer provided us written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.

ORGANIZATIONAL REALIGNMENT

In September 2016, we announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective January 1, 2017, we implemented these changes, which combined the management of certain of our operations and reduced the overall number of operating areas managed within our business.

Information in this report has generally been prepared to be consistent with the reportable segment presentation in our consolidated financial statements in Part II, Item 8 of this document. These segments are discussed in further detail in the following sections.

FINANCIAL INFORMATION ABOUT SEGMENTS

See “Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 19 – Segment Disclosures.”

BUSINESS SEGMENTS

Substantially all our operations are conducted through our subsidiaries. Our activities in 2016 were operated through the following reporting segments as presented in the accompanying financial statements and management’s discussion and analysis.

•

Williams Partners — comprised of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint project investments. The midstream business provides natural gas gathering, treating, processing and compression services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services; an olefin production business and is comprised of several wholly owned and partially owned subsidiaries and joint project investments.

Prior to September 2016, this reporting segment also included our Canadian midstream operations comprised of an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility, and the Boreal Pipeline which were subsequently sold.


•	Williams NGL & Petchem Services — comprised of our Texas Belle pipeline and certain other domestic olefins pipeline assets. Prior to September 2016, this reporting segment also included certain Canadian growth projects under development, including a propane dehydrogenation facility and a recently completed liquids extraction plant which were subsequently sold.


•	Other — primarily comprised of corporate operations and our Canadian construction services company.

As previously discussed, in September 2016 we announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective January 1, 2017, we implemented these changes, which combined the management of certain of our operations and reduced the overall number of operating areas managed within our business. As a result of this realignment and the sale of our Canadian operations, the Williams NGL & Petchem Services reporting segment will be eliminated and the remaining assets will be reported with Other.

Detailed discussion of each of our reporting segments follows. For a discussion of our ongoing expansion projects, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Williams Partners

Gas Pipeline Business

Williams Partners' gas pipeline businesses consist primarily of Transco and Northwest Pipeline. Our gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,230 TBtu of natural gas and peak-day delivery capacity of approximately 15.5 MMdth of natural gas.

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile natural gas pipeline system, which is regulated by the FERC, extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey, and Pennsylvania.

Pipeline system and customers

At December 31, 2016, Transco’s system had a mainline delivery capacity of approximately 6.6 MMdth of natural gas per day from its production areas to its primary markets, including delivery capacity from the mainline to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 5.1 MMdth of natural gas per day for a system-wide delivery capacity total of approximately 11.7 MMdth of natural gas per day. Transco’s system includes 47 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.8 million horsepower.

Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers interruptible transportation services under shorter-term agreements.

Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that it owns and operates. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas. At December 31, 2016, Transco’s customers had stored in its facilities approximately 151 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent equity-method investment in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

Northwest Pipeline

Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline system, which is regulated by the FERC, extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona, either directly or indirectly through interconnections with other pipelines.

Pipeline system and customers

At December 31, 2016, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery agreements with aggregate capacity reservations of approximately 3.8 MMdth/d, was composed of approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 472,000 horsepower.

Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies, public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers. Northwest Pipeline’s firm transportation and storage redelivery contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.

Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for natural gas storage services in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working natural gas storage capacity of 14.2 MMdth of natural gas, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to customers.

Gulfstream

Gulfstream is a 745-mile interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, which has a capacity to transport 1.3 Bcf/d. Williams Partners owns, through a subsidiary, a 50 percent equity-method investment in Gulfstream. Williams Partners shares operating responsibilities for Gulfstream with the other 50 percent owner.

Midstream Business

Williams Partners’ midstream business, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Arkansas, Colorado, New Mexico, Oklahoma, Texas, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio. The primary businesses are: (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; (3) crude oil transportation; and (4) olefins production. These fall within the middle of the process of taking raw natural gas and crude oil from the producing fields to the consumer. We also own and operate gas gathering and processing assets and pipelines primarily within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

Key variables for this business will continue to be:


•	Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;


•	Prices impacting commodity-based activities;


•	Retaining and attracting customers by continuing to provide reliable services;


•	Revenue growth associated with additional infrastructure either completed or currently under construction;


•	Disciplined growth in core service areas and new step-out areas.

Gathering, Processing, and Treating

Williams Partners’ gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Williams Partners’ treating facilities remove water vapor, carbon dioxide, and other contaminants and collect condensate, but do not extract NGLs. Williams Partners’ is generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.

In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide, and other contaminants. NGL products include:


•	Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;


•	Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials, and molded plastic parts;


•	Normal butane, isobutane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.

Our gas processing services generate revenues primarily from the following three types of contracts:

•

Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. A portion of our fee-based processing revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2016, 69 percent of the domestic NGL production volumes were under fee-based contracts.

•

Keep-whole: Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas, and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. NGLs we retain in connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2016, 26 percent of the domestic NGL production volumes were under keep-whole contracts.

•

Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2016, 5 percent of the domestic NGL production volumes were under percent-of-liquids contracts.

Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements. Some contracts have price escalators which annually increase our gathering rates. In addition, certain contracts include fee redetermination or cost of service mechanisms that are designed to support a return on invested capital and allow our gathering rates to be

adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, commodity price fluctuations, compression and other expenses. Certain of our gas gathering agreements include MVCs. If the minimum annual or semi-annual volume commitment is not met, these customers are obligated to pay a fee equal to the applicable fee for each Mcf by which the applicable customer’s minimum annual or semi-annual volume commitment exceeds the actual volume gathered. The revenue associated with such shortfall fees is generally recognized in the fourth quarter of each year.

Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Williams Partners’ gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding its infrastructure. During 2016, Williams Partners’ facilities gathered and processed gas for approximately 200 customers. Williams Partners’ top eight gathering and processing customers accounted for approximately 78 percent of our gathering and processing fee revenues and NGL margins from our keep-whole and percent-of-liquids agreements.

Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products are currently the preferred feedstock for ethylene and propylene production, which has shifted away from the more expensive crude-based feedstocks.

Geographically, the midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of the offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Our San Juan basin, southwest Wyoming, and Piceance systems are capable of delivering residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party interstate systems. Our gathering systems in Pennsylvania delivers residue gas volumes into Transco’s pipeline in addition to third-party interstate systems.

The following table summarizes our significant consolidated natural gas gathering assets:



	Natural Gas Gathering Assets
	Location	Pipeline Miles	Inlet Capacity (Bcf/d)	Ownership Interest	Supply Basins/Shale Formations
Northeast
Ohio Valley	West Virginia & Pennsylvania	210	0.8	100%	Appalachian
Susquehanna Supply Hub	Pennsylvania & New York	399	2.9	100%	Appalachian
Cardinal (1)	Ohio	352	1.0	66%	Appalachian
Flint	Ohio	33	0.2	100%	Appalachian
Marcellus South (2)	West Virginia & Pennsylvania	41	0.1	100%	Appalachian
Atlantic-Gulf
Canyon Chief, including Blind Faith and Gulfstar extensions	Deepwater Gulf of Mexico	156	0.5	100%	Eastern Gulf of Mexico
Other Eastern Gulf	Offshore shelf and other	46	0.2	100%	Eastern Gulf of Mexico
Seahawk	Deepwater Gulf of Mexico	115	0.4	100%	Western Gulf of Mexico
Perdido Norte	Deepwater Gulf of Mexico	105	0.3	100%	Western Gulf of Mexico
Other Western Gulf	Offshore shelf and other	120	0.9	100%	Western Gulf of Mexico
West
Four Corners	Colorado & New Mexico	3,743	1.8	100%	San Juan
Wamsutter	Wyoming	1,973	0.6	100%	Wamsutter
Southwest Wyoming	Wyoming	1,614	0.5	100%	Southwest Wyoming
Piceance	Colorado	336	1.5	(3)	Piceance
Niobrara	Wyoming	184	0.2	(4)	Powder River
Barnett Shale	Texas	858	0.9	100%	Barnett Shale
Eagle Ford Shale	Texas	1,010	0.7	100%	Eagle Ford Shale
Haynesville Shale	Louisiana	598	1.7	100%	Haynesville Shale
Permian	Texas	346	0.1	100%	Permian
Mid-Continent	Oklahoma & Kansas	2,112	0.9	100%	Miss-Lime, Granite Wash, Colony Wash

__________


(1)	Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system.


(2)	Statistics reflect 100 percent of the Beaver Creek assets from our 67 percent ownership in the Marcellus South gathering system.


(3)	Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and 0.2 Bcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of pipeline and 0.1 Bcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance of the Piceance gathering assets.


(4)	Includes our 50 percent ownership of the Jackalope gathering system.

The following table summarizes our significant consolidated natural gas processing facilities:



	Natural Gas Processing Facilities
	Location	Inlet Capacity (Bcf/d)	NGL Production Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Northeast
Fort Beeler	Marshall County, WV	0.5	62	100%	Appalachian
Oak Grove	Marshall County, WV	0.2	25	100%	Appalachian
Atlantic-Gulf
Markham	Markham, TX	0.5	45	100%	Western Gulf of Mexico
Mobile Bay	Coden, AL	0.7	30	100%	Eastern Gulf of Mexico
West
Echo Springs	Echo Springs, WY	0.7	58	100%	Wamsutter
Opal	Opal, WY	1.1	47	100%	Southwest Wyoming
Bucking Horse (1)	Converse County, WY	0.1	7	50%	Powder River
Willow Creek	Rio Blanco County, CO	0.5	30	100%	Piceance
Parachute	Garfield County, CO	1.1	6	100%	Piceance
Ignacio	Ignacio, CO	0.5	29	100%	San Juan
Kutz	Bloomfield, NM	0.2	12	100%	San Juan

__________


(1)	Statistics reflect 100 percent of the assets from our 50 percent ownership of Bucking Horse gas processing facility.

In addition, we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and Louisiana which bring natural gas to specifications allowable by major interstate pipelines.

We also own and operate fractionation facilities at Moundsville, de-ethanization and condensate facilities at our Oak Grove processing plant, another condensate stabilization facility near our Oak Grove plant, and an ethane transportation pipeline. Our two condensate stabilizers are capable of handling 17 Mbbls/d of field condensate. NGLs are extracted from the natural gas stream in our cryogenic processing plants. Our Oak Grove de-ethanizer is capable of handling up to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane. The remaining mixed NGL stream from the de-ethanizer is then transported and fractionated at our Moundsville facilities, which are capable of handling more than 42 Mbbls/d of mixed NGLs. Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania.

Our gathering business in the Northeast also provides multiple takeaway options to its customers. Ohio Valley Midstream makes customer deliveries with interconnections to two pipelines. Susquehanna Supply Hub makes deliveries for its customers with interconnections to Transco, as well as five other pipelines, while our Cardinal system utilizes interconnections with Blue Racer and UEOM. In addition, our NGL processing business utilizes connections with multiple pipelines, as well as truck and rail transportation to local and regional markets.

Crude Oil Transportation and Production Handling Assets

In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis. Fixed fees associated with the resident production at our Gulfstar One facility are recognized as the guaranteed capacity is made available.

The following tables summarize our significant crude oil transportation pipelines and production handling platforms:



	Crude Oil Pipelines
	Pipeline Miles	Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Mountaineer, including Blind Faith and Gulfstar extensions	172	150	100%	Eastern Gulf of Mexico
BANJO	57	90	100%	Western Gulf of Mexico
Alpine	96	85	100%	Western Gulf of Mexico
Perdido Norte	74	150	100%	Western Gulf of Mexico



	Production Handling Platforms
	Gas Inlet Capacity (MMcf/d)	Crude/NGL Handling Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Devils Tower	210	60	100%	Eastern Gulf of Mexico
Gulfstar I FPS (1)	172	80	51%	Eastern Gulf of Mexico

__________


(1)	Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.

Canadian Operations

Williams Partners completed the sale of its Canadian operations in September 2016. This business included an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility located at Redwater, Alberta, which is near Edmonton, Alberta, and the Boreal Pipeline which transported NGLs and associated olefins from the Fort McMurray plant to the Redwater fractionation facility. This business allowed us to extract, fractionate, treat, store, terminal and sell the ethane/ethylene, propane, propylene, normal butane (butane), iso-butane, alky feedstock, and condensate recovered from a third-party oil sands bitumen upgrader. The commodity price exposure of this asset was the spread between the price for natural gas and the NGL and olefin products we produce. These products were sold within Canada and the United States.

Operating statistics

The following table summarizes our significant operating statistics:



	2016	2015	2014
Volumes:
Canadian propylene sales (millions of pounds)	87	161	143
Canadian NGL sales (millions of gallons)	141	284	218

Gulf Olefins

We have an 88.5 percent undivided interest and operatorship of an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.

In 2015, we placed in service an expansion of the olefins production facility that increased its ethylene production capacity by 600 million pounds per year, for a total production capacity of 1.95 billion pounds of ethylene and 114 million pounds of propylene per year. Our feedstocks for the cracker are ethane and propane; as a result, these assets are primarily exposed to the price spread between ethane and propane, and ethylene and propylene, respectively. Ethane and propane are available for purchase from third parties and from affiliates. Following an explosion and fire that occurred in 2013, the Geismar plant resumed consistent operations in late March 2015 and reached full production capacity in the third quarter of 2015.

Our refinery grade propylene splitter has a production capacity of approximately 500 million pounds per year of propylene. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result, this asset is exposed to the price spread between those commodities.

We own 283 miles of pipeline systems in Louisiana and Texas that provide feedstock transportation to the Geismar olefins plant, the RPG Splitter, and other third-party crackers. These systems include the Bayou ethane pipeline, which provides ethane transportation from fractionation and storage facilities in Mont Belvieu, Texas, to the Geismar olefins plant in south Louisiana and serves customers along the way; as well as the Geismar ethane and propane systems in Louisiana, which provide feedstock transportation to the Geismar olefins plant and other customers. We also own a pipeline that has the capacity to supply 12 Mbbls/d of ethane from Discovery’s Paradis fractionator to the Geismar olefins plant.

As a merchant producer of ethylene and propylene, our product sales are to customers for use in making plastics and other downstream petrochemical products destined for both domestic and export markets. We are currently seeking to monetize our ownership interest in the Geismar, Louisiana, olefins plant and complex (see Overview within Management’s Discussion and Analysis of Financial Condition and Results of Operations).

Marketing Services

We market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets our equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. Other than a long-term agreement to sell our equity NGLs transported on OPPL, the majority of sales are based on supply contracts of one year or less in duration.

In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.

We also market olefin products to a wide range of users in the energy and petrochemical industries. In order to meet sales contract obligations, we may purchase olefin products for resale.

Other NGL & Petchem Operations

We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 20 million barrels of NGL storage capacity.

We own 114 miles of pipelines in the Houston Ship Channel area which transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel. A portion of these pipelines are leased to third parties.

WPZ Operating Areas

Effective January 1, 2017, WPZ organizes these businesses into the following operating areas:

Northeast G&P is comprised of natural gas gathering and processing, compression, and NGL fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns an approximate average 41 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

Atlantic-Gulf is comprised of an interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity) which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is under development, and a 60 percent equity-method investment in Discovery.

West is comprised of an interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. West also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, as well as a 50 percent equity-method investment in the Delaware basin gas gathering system in the Permian basin, and a 50 percent equity-method investment in OPPL.

NGL & Petchem Services is comprised of our 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter. Prior to September 2016, this operating area also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility which were subsequently sold.

Certain Equity-Method Investments

Discovery

We own a 60 percent interest in and operate the facilities of Discovery. Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and a 614-mile offshore natural gas gathering and transportation system in the Gulf of Mexico with an inlet capacity of 1,350 MMcf/d, including the Keathley Canyon Connector, a 209-mile deepwater lateral pipeline in the central deepwater Gulf of Mexico that contributes 400 MMcf/d of inlet capacity. Discovery’s assets also include a crude oil production handling platform with a crude oil/NGL handling capacity of 10 Mbbls/d and natural gas processing capacity of 75 MMcf/d.

Laurel Mountain

We own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 2,053-mile gathering system that we operate in western Pennsylvania with the capacity to gather 0.7 Bcf/d of natural gas. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale.

Caiman II

We own a 58 percent interest in Caiman II, which owns a 50 percent interest in Blue Racer, a joint project to own, operate, develop and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 688 miles of natural gas gathering pipelines, including 422 miles of large-diameter pipelines, and the Natrium complex in Marshall County, West Virginia, with a cryogenic processing capacity of 400 MMcf/d and fractionation capacity of approximately 123,000 Bbls/d. Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne.

Utica East Ohio Midstream

We own a 62 percent interest in UEOM, a joint project to develop infrastructure for the gathering, processing and fractionation of natural gas and NGLs in the Utica Shale play in eastern Ohio. We, along with other equity owners, operate the infrastructure complex which consists of natural gas gathering and compression facilities, four processing plants with a total capacity of 800 MMcf/d, 41 Mbbls/d of condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility, approximately 950,000 barrels of NGL storage capacity and other ancillary assets, including

loading and terminal facilities that are operated by our partner. These assets earn a fixed fee that escalates annually within a specified range.

Aux Sable

We own a 14.6 percent interest in Aux Sable and its Channahon, Illinois, gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 107 Mbbls/d of extracted liquids into NGL products. Additionally, Aux Sable owns an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.

Appalachia Midstream Investments

Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 41 percent interest in multiple natural gas gathering systems that consist of approximately 979 miles of gathering pipeline in the Marcellus Shale region. The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. Appalachia Midstream Investments operates the assets under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications and cost of service mechanisms.

Delaware basin gas gathering system

We own a non-operated 50 percent interest in the Delaware basin gas gathering system (DBJV) in the Permian basin. The system is comprised of more than 450 miles of gathering pipeline, located in west Texas.

Acquisition of Additional Interests in Appalachia Midstream Investments

In February 2017, we announced agreements to acquire additional interests in two Marcellus Shale gathering systems within Appalachia Midstream Investments in exchange for equity-method investment interests in DBJV and the Ranch Westex gas processing plant. We also expect to receive a total of $200 million in cash as part of the agreements, subject to customary closing conditions and purchase price adjustments. The transactions are expected to close in late first-quarter or early second-quarter 2017.

Overland Pass Pipeline

We operate and own a 50 percent interest in OPPL. OPPL is capable of transporting 255 Mbbls/d and includes approximately 1,096 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado and the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from two of our three Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement.

Operating Statistics

The following table summarizes our significant operating statistics for Williams Partners’ domestic midstream business:



	2016	2015	2014
Volumes: (1)
Gathering (Bcf/d)	8.25	8.34	8.90
Plant inlet natural gas (Bcf/d)	3.50	3.52	3.82
NGL production (Mbbls/d) (2)	151	131	128
NGL equity sales (Mbbls/d) (2)	46	31	27
Crude oil transportation (Mbbls/d) (2)	113	126	105
Geismar ethylene sales (millions of pounds)	1,638	1,066	—

__________


(1)	Excludes volumes associated with equity-method investments.


(2)	Annual average Mbbls/d.

Williams NGL & Petchem Services

The Williams NGL & Petchem Services segment is comprised of our Texas Belle pipeline and certain other domestic olefins pipeline assets. Prior to its sale in September 2016, this reporting segment also included the Horizon liquids extraction plant which was placed in service in March 2016 and a propane dehydrogenation facility which was under development. As this segment is currently comprised primarily of projects under development, reported revenues to-date are nominal. Effective January 1, 2017, these assets will be reported in Other.

Additional Business Segment Information

Our ongoing business segments are presented as continuing operations in the accompanying financial statements and Notes to Consolidated Financial Statements included in Part II.

We perform certain management, legal, financial, tax, consultation, information technology, administrative and other services for our subsidiaries.

Our principal sources of cash are from dividends, distributions, and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, and, if needed, external financings, and net proceeds from asset sales. The terms of certain subsidiaries’ borrowing arrangements may limit the transfer of funds to us under certain conditions.

We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. Our interstate pipeline systems are all regulated in various ways resulting in the financial return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays.

Revenues by service within our Williams Partners segment that exceeded 10 percent of consolidated revenue include:



	Total
	(Millions)
2016
Service:
Regulated natural gas transportation and storage	$	2,001
Gathering, processing, and production handling	2,729
2015
Service:
Regulated natural gas transportation and storage	$	1,938
Gathering, processing, and production handling	2,804
2014
Service:
Regulated natural gas transportation and storage	$	1,781
Gathering, processing and production handling	1,838

We have one customer, Chesapeake Energy Corporation, and its affiliates, that accounts for 14 percent of our total revenue in 2016. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for additional details.)

REGULATORY MATTERS

FERC

Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement, or abandonment of

our jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities, and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit gas marketing functions.

FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect. Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are:


•	Costs of providing service, including depreciation expense;


•	Allowed rate of return, including the equity component of the capital structure and related income taxes;


•	Contract and volume throughput assumptions.

The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.

We also own interests in and operate two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. In addition, Williams Partners owns a 50 percent equity-method investment in and is the operator of OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.

Pipeline Safety

Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016, which regulate safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.

Federal pipeline safety laws authorize PHMSA to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. PHMSA has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.

Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations. A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal law. However, PHMSA is completing a congressionally-mandated review of the adequacy of the existing federal and state regulations for gathering lines and has indicated that it may apply additional safety standards to rural gas gathering lines in the future.

States are largely preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by PHMSA to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate

pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.

On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires PHMSA to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements for both gas and liquid pipeline systems. On June 22, 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 was enacted, further strengthening PHMSA’s safety authority.

Pipeline Integrity Regulations

We have developed an enterprise-wide Gas Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for gas transmission pipelines that could affect high-consequence areas in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified high-consequence areas and developed baseline assessment plans. Ongoing periodic reassessments and initial assessments of any new high-consequence areas have been completed. We estimate that the cost to be incurred in 2017 associated with this program to be approximately $57 million. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest Pipeline’s and Transco’s rates.

We developed a Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect high-consequence areas in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments expected to be completed within required time frames. In meeting the integrity regulations, we utilized government defined high-consequence areas and developed baseline assessment plans. We completed assessments within the required time frames. We estimate that the cost to be incurred in 2017 associated with this program will be approximately $7 million. Ongoing periodic reassessments and initial assessments of any new high-consequence areas are expected to be completed within the time frames required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.

State Gathering Regulation

Our onshore midstream gathering operations are subject to laws and regulations in the various states in which we operate. For example, the Texas Railroad Commission has the authority to regulate the terms of service for our intrastate natural gas gathering business in Texas. Although the applicable state regulations vary widely, they generally require that pipeline rates and practices be reasonable and nondiscriminatory, and may include provisions covering marketing, pricing, pollution, environment, and human health and safety. Some states, such as New York, have specific regulations pertaining to the design, construction, and operations of gathering lines within such state.

OCSLA

Our offshore midstream gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Although offshore gathering facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and in recent years the FERC has taken a broad view of offshore transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most offshore gathering facilities are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonowner shippers.”

Olefins

Our olefins assets are regulated by the Louisiana Department of Environmental Quality, the Texas Railroad Commission, and various other state and federal entities regarding our liquids pipelines.

These olefins assets are also subject to the liquid pipeline safety and integrity regulations previously discussed above since both Louisiana and Texas have adopted the integrity management regulations defined by PHMSA.

See Note 18 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements for further details on our regulatory matters. For additional information regarding regulatory matters, please also refer to “Risk Factors — The operation of our businesses might also be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers,” and “The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return."

ENVIRONMENTAL MATTERS

Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:


•	Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities, and storage tanks;


•	Damage to facilities resulting from accidents during normal operations;


•	Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;


•	Blowouts, cratering, and explosions.

In addition, we may be liable for environmental damage caused by former owners or operators of our properties.

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings, or current competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.

For additional information regarding the potential impact of federal, state, tribal, or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors — “Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed current expectations,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Note 18 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.

COMPETITION

Gas Pipeline Business

The market for supplying natural gas is highly competitive and new pipelines, storage facilities, and other related services are expanding to service the growing demand for natural gas. Additionally, pipeline capacity in many growing natural gas supply basins is constrained causing competition to increase among pipeline companies as they strive to connect those basins to major natural gas demand centers.

In our business, we compete with major intrastate and interstate natural gas pipelines. In the last few years, local distribution companies have also started entering into the long haul transportation business through joint venture pipelines. The principle elements of competition in the interstate natural gas pipeline business are based on rates, reliability, quality of customer service, diversity of supply, and proximity to customers and market hubs.

Significant entrance barriers to build new pipelines exist, including federal and growing state regulations and public opposition against new pipeline builds, and these factors will continue to impact potential competition for the foreseeable future. However, we believe the position of our existing infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and delivery points along our systems provide us a competitive advantage, especially along the eastern seaboard and northwestern United States.

Midstream Business

Competition for natural gas gathering, processing, treating, transporting, and storing natural gas continues to increase as production from shales and other resource areas continues to grow. Our midstream services compete with similar facilities that are in the same proximity as our assets.

We face competition from major and independent natural gas midstream providers, private equity firms, and major integrated oil and natural gas companies that gather, transport, process, fractionate, store, and market natural gas and NGLs, as well as some larger exploration and production companies that are choosing to develop midstream services to handle their own natural gas.

Our gathering and processing agreements are generally long-term agreements that may include acreage dedication. We primarily face competition to the extent these agreements approach renewal and new volume opportunities arise. Competition for natural gas volumes is primarily based on reputation, commercial terms (products retained or fees charged), array of services provided, efficiency and reliability of services, location of gathering facilities, available capacity, downstream interconnects, and latent capacity. We believe our significant presence in traditional prolific supply basins, our solid positions in growing shale plays, and our ability to offer integrated packages of services position us well against our competition.

Our olefins business (primarily ethylene and propylene production), competes in a worldwide market place. However, the majority of North American olefins producers have significant downstream petrochemical manufacturing for plastics and other petrochemical products. We participate as a merchant seller of olefins with no downstream petrochemical manufacturing; therefore, at any time we can be either a supplier or a competitor to these companies. We compete on the basis of service, price, and availability of products that we produce.

For additional information regarding competition for our services or otherwise affecting our business, please refer to “Risk Factors - The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access, and demand for those supplies in the markets we serve,” “Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results,” and “We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.”

EMPLOYEES

At February 1, 2017, we had approximately 5,604 full-time employees.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

See Note 19 – Segment Disclosures of Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to the United States and all foreign countries. Also see Note 19 – Segment Disclosures of Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.

Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT

FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

The reports, filings and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical fact, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in service date” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:


•	Levels of cash distributions by Williams Partners L.P. (WPZ) with respect to limited partner interests;


•	Levels of dividends to Williams stockholders;


•	Future credit ratings of Williams, WPZ, and their affiliates;


•	Amounts and nature of future capital expenditures;


•	Expansion and growth of our business and operations;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Seasonality of certain business components;


•	Natural gas, natural gas liquids, and olefins prices, supply, and demand;


•	Demand for our services.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:


•	Whether WPZ will produce sufficient cash flows to provide the level of cash distributions that we expect;


•	Whether we are able to pay current and expected levels of dividends;


•	Whether WPZ elects to pay expected levels of cash distributions and we elect to pay expected levels of dividends;


•	Whether we will be able to effectively execute our financing plan including the receipt of anticipated levels of proceeds from planned asset sales;


•	Whether we will be able to effectively manage the transition in our board of directors and management as well as successfully execute our business restructuring;


•	Availability of supplies, including lower than anticipated volumes from third parties served by our midstream business, and market demand;


•	Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;


•	Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);


•	The strength and financial resources of our competitors and the effects of competition;


•	Whether we are able to successfully identify, evaluate, and timely execute our capital projects and other

investment opportunities in accordance with our forecasted capital expenditures budget;


•	Our ability to successfully expand our facilities and operations;


•	Development of alternative energy sources;


•	Availability of adequate insurance coverage and the impact of operational and developmental hazards and unforeseen interruptions;


•	The impact of existing and future laws, regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain permits and achieve favorable rate proceeding outcomes;


•	Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;


•	Changes in maintenance and construction costs;


•	Changes in the current geopolitical situation;


•	Our exposure to the credit risk of our customers and counterparties;


•	Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies and the availability and cost of capital;


•	The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;


•	Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;


•	Acts of terrorism, including cybersecurity threats and related disruptions;


•	Additional risks described in our filings with the Securities and Exchange Commission (SEC).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, prospects, financial condition, results of operations, cash flows and, in some cases our reputation. The occurrence of any of such risks could also adversely affect the value of an investment in our securities.

Litigation pertaining to the ETC Merger, including litigation related to Energy Transfer Equity, L.P.’s (ETE’s) termination of and failure to close the ETC Merger, may negatively impact our business and operations.

We have incurred and may continue to incur additional costs in connection with the prosecution, defense or settlement of the currently pending and any future litigation relating to the ETC Merger or ETE’s termination of and failure to close the ETC Merger. Such litigation includes, among other litigation matters, litigation brought by stockholders of us and unitholders of WPZ related to the ETC Merger and/or Williams’ termination of the merger agreement with WPZ. Such litigation also includes the on-going litigation against ETE and its affiliates a portion of which is on appeal in the Delaware Supreme Court and in which ETE has asserted counterclaims against us. We continue to believe that our lawsuit against ETE and its affiliates is an enforcement of our rights under the Merger Agreement and that this lawsuit is designed to deliver to our stockholders benefits under the Merger Agreement. We cannot predict the outcome of this litigation. Such litigation may also create a distraction for our management team and board of directors and require time and attention. In addition, any litigation relating to the ETC Merger or ETE’s termination of and failure to close the ETC Merger could, among other things, adversely affect our financial condition and results of operations.

We are exposed to the credit risk of our customers and counterparties, including Chesapeake Energy Corporation and its affiliates, and our credit risk management will not be able to completely eliminate such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility,

deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment certain of our customers could be negatively impacted, causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows, and financial conditions. For example, Chesapeake Energy Corporation and its affiliates, which accounted for approximately 14 percent of our 2016 consolidated revenues, have experienced significant, negative financial results due to sustained low commodity prices. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Prices for NGLs, olefins, natural gas, oil, and other commodities, are volatile and this volatility has and could continue to adversely affect our financial results, cash flows, access to capital, and ability to maintain our existing businesses.

Our revenues, operating results, future rate of growth, and the value of certain components of our businesses depend primarily upon the prices of NGLs, olefins, natural gas, oil, or other commodities, and the differences between prices of these commodities, and could be materially adversely affected by an extended period of current low commodity prices or a further decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.

The markets for NGLs, olefins, natural gas, oil, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:


•	Worldwide and domestic supplies of and demand for natural gas, NGLs, olefins, oil, and related commodities;


•	Turmoil in the Middle East and other producing regions;


•	The activities of the Organization of Petroleum Exporting Countries;


•	The level of consumer demand;


•	The price and availability of other types of fuels or feedstocks;


•	The availability of pipeline capacity;


•	Supply disruptions, including plant outages and transportation disruptions;


•	The price and quantity of foreign imports of natural gas and oil;


•	Domestic and foreign governmental regulations and taxes;


•	The credit of participants in the markets where products are bought and sold.

Downgrades of our credit ratings, which are determined outside of our control by independent third parties, impact our liquidity, access to capital, and our costs of doing business.

Downgrades of our credit ratings increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could continue to be limited by the downgrading of our credit ratings.

Credit rating agencies perform independent analysis when assigning credit ratings. This analysis includes a number of criteria such as, business composition, market, and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies. As of the date of the filing of this report, we have been assigned below investment-grade credit ratings by each of the three credit ratings agencies.

Our ability to obtain credit in the future could be affected by WPZ’s credit ratings.

A substantial portion of our operations are conducted through, and our cash flows are substantially derived from distributions paid to us by, WPZ. Due to our relationship with WPZ, our ability to obtain credit will be affected by WPZ’s credit ratings. If WPZ were to experience a deterioration in its credit standing or financial condition, our access to capital, and our ratings could be adversely affected. Any future downgrading of a WPZ credit rating could also result in a downgrading of our credit rating. A downgrading of a WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve.

Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems and processing facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, or the lack of available capital could adversely affect the development and production of additional natural gas reserves, the installation of gathering, storage, and pipeline transportation facilities and the import and export of natural gas supplies. Localized low natural gas prices in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas made available to us. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation, and processing facilities.

Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business.

A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows.

We may not be able to grow or effectively manage our growth.

As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We have both a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines, and facilities, NGL transportation, or fractionation or storage facilities as well as the expansion of existing facilities.

We also face all the risks associated with construction, including political opposition by landowners, environmental activists, and others resulting in the delay and/or denial of required governmental permits. Other construction risks include the inability to obtain rights-of-way, skilled labor, equipment, materials, and other required inputs in a timely manner such that projects are completed, on time or at all, and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:


•	Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;


•	We could be required to contribute additional capital to support acquired businesses or assets;


•	We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;


•	Acquisitions could disrupt our ongoing business, distract management, divert financial, and operational resources from existing operations and make it difficult to maintain our current business standards, controls, and procedures;


•	Acquisitions and capital projects may require substantial new capital, including the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.

If realized, any of these risks could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows.

We do not own all of the interests in the Partially Owned Entities, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.

Because we do not control the Partially Owned Entities, we may have limited flexibility to control the operation of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents generally require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. As of December 31, 2016, our investments in the Partially Owned Entities accounted for approximately 8 percent of our total consolidated assets. Conflicts of interest may arise in the future between us, on the one hand, and our Partially Owned Entities, on the other hand, with regard to our Partially Owned Entities’ governance, business, or operations. If a conflict of interest arises between us and a Partially Owned Entity, other owners may control the Partially Owned Entity’s actions with respect to such matter (subject to certain limitations), which could be detrimental to our business. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Holders of our common stock may not receive dividends in the amount expected or any dividends.

We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:


•	The amount of cash that WPZ and our other subsidiaries distribute to us;


•	The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;


•	The restrictions contained in our indentures and credit facility and our debt service requirements;


•	The cost of acquisitions, if any.

A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of our stock price.

Our cash flow depends heavily on the earnings and distributions of WPZ.

Our partnership interest in WPZ is currently our largest cash-generating asset. Therefore, we are, at the least, indirectly exposed to all the risks to which WPZ is subject and our cash flow is heavily dependent upon the ability of WPZ to make distributions to its partners. A significant decline in WPZ’s earnings and/or distributions would have a corresponding negative impact on us.

We may not be able to sell assets or, if we are able to sell assets, to raise a sufficient amount of capital from such asset sales. In addition, the timing to enter into and close any asset sales could be significantly different than our expected timeline.

We are planning to monetize certain assets held by our subsidiaries in 2017 (including without limitation the Geismar olefins facility owned by WPZ) to fund additional debt reduction and capital and investment expenditures. Given the commodity markets, financial markets, and other challenges currently facing the energy sector, our competitors may also engage in asset sales leading to lower demand for the assets we wish to sell. We may not be able to sell the assets we identify for sale on favorable terms or at all. If we are able to sell assets, the timing of the receipt of the asset sale proceeds may not align with the timing of our capital requirements. A failure to raise sufficient capital from asset sales or a misalignment of the timing of capital raised and capital funding needs could have an adverse impact on our business, financial condition, results of operations, and cash flows.

An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce our earnings.

GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our goodwill, property, plant, and equipment, intangible assets, and/or equity method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings.

Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.

We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Some of our competitors are large oil, natural gas, and petrochemical companies that have greater access to supplies

of natural gas and NGLs than we do. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion, or refurbishment of their facilities than we can. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition, and cash flows.

We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.

We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers, or otherwise increase the contracted volumes of natural gas provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay dividends could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:


•	The level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy;

•

Natural gas, NGL, and olefins prices, demand, availability, and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;


•	General economic, financial markets, and industry conditions;


•	The effects of regulation on us, our customers, and our contracting practices;


•	Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.

Some of our businesses are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers.

Some of our businesses may be dependent on a small number of suppliers for delivery of critical goods or services. For instance, pursuant to a compression services agreement, one of our businesses receives a substantial portion of its compression capacity on certain gathering systems from EXLP Operating LLC (“Exterran Operating”). Exterran Operating has, until December 31, 2020, the exclusive right to provide compression services on certain gas gathering systems located in Wyoming, Texas, Oklahoma, Louisiana, and Arkansas, in return for the payment of specified monthly rates for the services provided, subject to an annual escalation provision. If a supplier on which one of our businesses depends were to fail to timely supply required goods and services, such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on our financial condition, results of operation, and cash flows.

We will conduct certain operations through joint ventures that may limit our operational flexibility or require us to make additional capital contributions.

Some of our operations are conducted through joint venture arrangements, and we may enter additional joint ventures in the future. In a joint venture arrangement, we have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases:


•	We cannot control the amount of capital expenditures that we are required to fund with respect to these operations;


•	We are dependent on third parties to fund their required share of capital expenditures;


•	We may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets;


•	We may be forced to offer rights of participation to other joint venture participants in the area of mutual interest;


•	We have limited ability to influence or control certain day to day activities affecting the operations.

In addition, joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance and ability of third parties to satisfy their obligations under joint venture arrangements is outside our control. If these third parties do not satisfy their obligations under these arrangements, our business may be adversely affected. Joint venture partners may be in a position to take actions contrary to instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

If we fail to make a required capital contribution under the applicable governing provisions of a joint venture arrangements, we could be deemed to be in default under the joint venture agreement. Joint venture partners may be permitted to fund any deficiency resulting from our failure to make such capital contribution, which would result in a dilution of our ownership interest, or such joint venture partners may have the option to purchase all of our existing interest in the subject joint venture.

The risks described above or the failure to continue joint ventures, or to resolve disagreements with joint venture partners could adversely affect our ability to conduct our operations that are the subject of any joint venture, which could in turn negatively affect our financial condition and results of operations.

Our operations are subject to operational hazards and unforeseen interruptions.

There are operational risks associated with the gathering, transporting, storage, processing, and treating of natural gas, the fractionation, transportation, and storage of NGLs, the processing of olefins, and crude oil transportation and production handling, including:


•	Aging infrastructure and mechanical problems;


•	Damages to pipelines and pipeline blockages or other pipeline interruptions;


•	Uncontrolled releases of natural gas (including sour gas), NGLs, olefins products, brine, or industrial chemicals;


•	Collapse or failure of storage caverns;


•	Operator error;


•	Damage caused by third-party activity, such as operation of construction equipment;


•	Pollution and other environmental risks;


•	Fires, explosions, craterings, and blowouts;


•	Truck and rail loading and unloading;


•	Operating in a marine environment.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. We currently maintain excess liability insurance with limits of $820 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us, our subsidiaries, and certain of our affiliates for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.

Although we maintain property insurance on certain physical assets that we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or be sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self-insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss is due to a named windstorm event, but coverage for loss caused by a named windstorm is subject to a significant sub-limit and to a large deductible. All of our insurance is subject to deductibles.

In addition, to the insurance coverage described above, we are a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured member of OIL, we share in the losses among other OIL members even if our property is not damaged.

The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability to repay our debt.

Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.

Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires, and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the

historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Acts of terrorism could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Given the volatile nature of the commodities we transport, process, store, and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, or distribute natural gas, NGLs, or other commodities. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.

We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies, practices, and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants, and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. The age, operating systems, or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information.

Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, or the loss of contracts, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows.

The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.

In addition to regulation by other federal, state, and local regulatory authorities, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:


•	Transportation and sale for resale of natural gas in interstate commerce;


•	Rates, operating terms, types of services, and conditions of service;


•	Certification and construction of new interstate pipelines and storage facilities;


•	Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;


•	Accounts and records;


•	Depreciation and amortization policies;


•	Relationships with affiliated companies who are involved in marketing functions of the natural gas business;


•	Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.

Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs, and otherwise altering the profitability of our pipeline business.

Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations.

Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation, transportation, and storage of NGLs, processing of olefins, and crude oil transportation and production handling as well as waste disposal practices and construction activities. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays or denials in granting permits.

Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

In addition, climate change regulations and the costs associated with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business. Regulatory actions by the Environmental Protection Agency or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, or (iii) administer and manage our GHG compliance program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated, or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

The operation of our businesses might also be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise enforced in a manner which differs from prior regulatory action. New laws and regulations, including those pertaining to oil and gas hedging and cash collateral requirements, might also be adopted or become applicable to us, our customers, or our business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process, and treat could decline, our compliance costs could increase, and our results of operations could be adversely affected.

Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

Our gas pipelines provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally

subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

Our operating results for certain components of our business might fluctuate on a seasonal basis.

Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited terms. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.

Our businesses may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above.

Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.

Our total outstanding long-term debt (including current portion) as of December 31, 2016, was $23.41 billion.

The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants, and other limitations with which we will need to comply.

Our debt service obligations and the covenants described above could have important consequences. For example, they could:


•	Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;


•	Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;


•	Diminish our ability to withstand a continued or future downturn in our business or the economy generally;


•	Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes, or other purposes;


•	Limit our flexibility in planning for, or reacting to, changes in our business, and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.

Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.

The Company’s business could be negatively impacted as a result of stockholder activism.

In recent years, stockholder activism, including threatened or actual proxy contests, has been directed against numerous public companies, including the Company. During the latter part of fiscal year 2016, the Company was the target of a proxy contest from a stockholder activist, which resulted in significant costs to the Company. If stockholder activists were to again take or threaten to take actions against the Company, the Company could incur significant costs as well as the distraction of management, which could have an adverse effect on the Company’s financial results. Stockholder activists may also seek to involve themselves in the governance, strategic direction, and operations of the Company. Such proposals may disrupt the Company’s business and divert the attention of the Company’s management and employees; and any perceived uncertainties as to the Company’s future direction resulting from such a situation could result in the loss of potential business opportunities, the perception that the Company needs a change in the direction of its business, or the perception that the Company is unstable or lacks continuity, any or all of which may be exploited by our competitors, cause concern to our current or potential customers, and may make it more difficult for the Company to attract and retain qualified personnel and business partners, which could adversely affect the Company’s business. In addition, actions of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business.

We are experiencing significant change in the composition of our Board of Directors and senior management.

On June 30, 2016, Frank T. MacInnis stepped down as Chairman of the Board and Kathleen B. Cooper was appointed as Chairman of the Board. Also on June 30, 2016, each of Ralph Izzo, Frank T. MacInnis, Eric W. Mandelblatt, Keith A. Meister, Steven W. Nance, and Laura A. Sugg resigned from the Board. On August 28, 2016, the Board appointed three new independent directors to the Board: Stephen W. Bergstrom, Scott D. Sheffield, and William H. Spence; on September 23, 2016, the Board appointed two additional new independent directors to the Board: Stephen I. Chazen and Peter A. Ragauss; and on December 5, 2016, the Board appointed two more additional new independent

directors to the Board: Charles “Casey” Cogut and Michael A. Creel. Three of Williams former directors, Joseph R. Cleveland, John A. Hagg, and Juanita H. Hinshaw, determined not to stand for re-election at the Company’s November 23, 2016 annual meeting. Thus, the Board is now composed of eleven directors, seven of whom were appointed in the second half of 2016.

On December 13, 2016, the Company announced the retirement of Senior Vice President Robert S. Purgason, effective January 31, 2017. The Company is also executing on a restructuring process, shifting from five operating areas to three, and on February 14, 2017 the Company announced the appointment of Micheal Dunn as Executive Vice President and Chief Operating Officer.

The changes in composition of the Company’s board and management impose an additional demand for attention, time and energy of board members and management in connection with orientation and education of new members about the Company, including with regard to its business strategies and objectives, assets and operations, and policies and practices, which could distract the board and management from execution of the Company’s strategy and objectives. Additionally, such changes invite new analysis of our business as the new members contribute to the formulation of our business strategies and objectives, which could implicate changes to such strategy and objectives. It is possible that changes to the composition of our board and management could have a negative impact on our business, financial condition, and results of operations.

Institutional knowledge residing with current employees nearing retirement eligibility or with our former employees might not be adequately preserved.

We expect that a significant percentage of employees will become eligible for retirement over the next several years. In addition, as part of an internal restructuring, we recently announced the reduction of five operating areas into three and the closing of our Oklahoma City office and the consolidation of employee positions to Tulsa or other locations. As employees with significant institutional knowledge reach retirement age, choose not to relocate with us, or their services are otherwise no longer available to us, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals, and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting, and retention efforts are inadequate, access to significant amounts of knowledge and expertise could become unavailable to us.

Our hedging activities might not be effective and could increase the volatility of our results.

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into, contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.

One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P. As such, this subsidiary’s operations may involve a greater risk of liability than ordinary business operations.

One of our subsidiaries acts as the general partner of WPZ, a publicly traded limited partnership. This subsidiary may be deemed to have undertaken contractual obligations with respect to WPZ as the general partner and to the limited partners of WPZ. Activities, determined to involve such obligations to other persons or entities typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WPZ may increase the possibility of claims of breach of such duties, including claims brought due to conflicts of interest (including conflicts

of interest that may arise between WPZ, on the one hand, and its general partner and that general partner’s affiliates, including us, on the other hand). Any liability resulting from such claims could be material.

Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.

Certain of our accounting and information technology services are currently provided by third-party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on others as service providers could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.

We have defined benefit pension plans covering substantially all of our U.S. employees and other postretirement benefit plans covering certain eligible participants. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest rates, and changes in pension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations.

If there is a determination that the spin-off of WPX Energy, Inc. (WPX) stock to our stockholders is taxable for U.S. federal income tax purposes because the facts, representations or undertakings underlying a U.S. Internal Revenue Service (IRS) private letter ruling or a tax opinion are incorrect or for any other reason, then we and our stockholders could incur significant income tax liabilities.

In connection with our original separation plan that called for an initial public offering (IPO) of stock of WPX and a subsequent spin-off of our remaining shares of WPX to our stockholders, we obtained a private letter ruling from the IRS and an opinion of our outside tax advisor, to the effect that the distribution by us of WPX shares to our stockholders, and any related restructuring transaction undertaken by us, would not result in recognition for U.S. federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the U.S. Internal Revenue Code of 1986, as amended (Code), except for cash payments made to our stockholders in lieu of fractional shares of WPX common stock. In addition, we received an opinion from our outside tax advisor to the effect that the spin-off pursuant to our revised separation plan which was ultimately consummated on December 31, 2011, which did not involve an IPO of WPX shares, would not result in the recognition, for federal income tax purposes, of income, gain, or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX. The private letter ruling and opinion have relied on or will rely on certain facts, representations, and undertakings from us and WPX regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, representations, or undertakings are, or become, incorrect or are not otherwise satisfied, including as a result of certain significant changes in the stock ownership of us or WPX after the spin-off, or if the IRS disagrees with any such facts and representations upon audit, we and our stockholders may not be able to rely on the private letter ruling or the opinion of our tax advisor and could be subject to significant income tax liabilities.

The spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements that we did not assume in our agreements with WPX.

The spin-off is subject to review under various state and federal fraudulent conveyance laws. A court could deem the spin-off or certain internal restructuring transactions undertaken by us in connection with the separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay, or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor

insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could adversely affect our financial condition and our results of operations. Whether a transaction is a fraudulent conveyance or transfer will vary depending upon the jurisdiction whose law is being applied. Under the separation and distribution agreement between us and WPX, from and after the spin-off, each of WPX and we are responsible for the debts, liabilities, and other obligations related to the business or businesses which each owns and operates. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to WPX, particularly if WPX were to refuse or were unable to pay or perform the subject allocated obligations.

Increases in interest rates could adversely impact our share price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash dividends at our intended levels.

Interest rates may increase further in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our share price will be impacted by the level of our dividends and implied dividend yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses, or consents on and across properties owned by others.

Item 3. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

On January 21, 2016, we received a Compliance Order from the Pennsylvania Department of Environmental Protection requiring the correction of several alleged deficiencies arising out of the construction of the Springville Gathering Line, the Pennsylvania Mainline Gathering Line, and the 2008 Core Zone Gathering Line. The original Order identified civil penalties in the amount of approximately $712,000. On December 28, 2016, we entered into an Order with the Pennsylvania Department of Environmental Protection to address the issues and paid the associated penalty of $581,477.

On February 21, 2017, we received notice from the Environmental Enforcement Section of the United States Department of Justice regarding certain alleged violations of the Clean Air Act at our Moundsville facility as set forth in a Notice of Noncompliance issued by the EPA on January 14, 2016. The notice includes an offer to avoid further legal action on the alleged violations by paying $2,000,000. We are currently evaluating the communication and our response.

Other

The additional information called for by this item is provided in Note 18 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this item.

Item 4. Mine Safety Disclosures

Not applicable.

Executive Officers of the Registrant

The name, age, period of service, and title of each of our executive officers as of February 22, 2017, are listed below. As previously discussed, Williams Partners L.P. merged with ACMP in February 2015 (the ACMP Merger). ACMP was the surviving entity in the ACMP Merger and changed its name to Williams Partners L.P. References in the biographical information below to (a) “Pre-merger WPZ” will mean Williams Partners L.P. prior to the ACMP Merger and (b) “ACMP/WPZ” will refer to both ACMP prior to and after the ACMP Merger, when it changed its name to Williams Partners L.P.



Alan S. Armstrong	Director, Chief Executive Officer, and President
	Age: 54
	Position held since 2011.
	From 2002 to 2011, Mr. Armstrong served as Senior Vice President - Midstream and acted as President of our midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in our midstream business and from 1998 to 1999 was Vice President, Commercial Development. Mr. Armstrong has served as a director of the general partner of ACMP/WPZ since 2012, as Chief Executive Officer since December 31, 2014, and as Chairman of the Board since February 2, 2015. Mr. Armstrong has served as a director of BOK Financial Corporation, a financial services company, since 2013. Mr. Armstrong also served as Chairman of the Board and Chief Executive Officer of the general partner of Pre-merger WPZ from 2011 until the ACMP Merger, as Senior Vice President - Midstream from 2010 to 2011, and director and Chief Operating Officer from 2005 to 2010.



Walter J. Bennett	Senior Vice President — West
	Age: 47
	Position held since January 2015.
	Mr. Bennett was formerly Chief Operating Officer of Chesapeake Midstream Development and served as Senior Vice President-Operations at Boardwalk Pipeline Partners. Previously, Mr. Bennett served in a variety of senior positions at Gulf South Pipeline Company that included operations and commercial responsibilities. Mr. Bennett began his career at a subsidiary of Koch Industries. Mr. Bennett has served as Senior Vice President - West of the general partner of ACMP/WPZ since December 2013 and served as Senior Vice President - West of the general partner of Pre-merger WPZ from January 2015 until the ACMP Merger. He has served as a director of the general partner of ACMP/WPZ since February 2017.



Francis (Frank) E. Billings	Senior Vice President — Corporate Strategic Development
	Age: 54
	Position held since January 2014.
	Mr. Billings served as Senior Vice President - Northeast G&P of us and Pre-merger WPZ from January 2013 to January 2014. Mr. Billings served as Vice President of our midstream gathering and processing business from 2011 until 2013 and as Vice President, Business Development from 2010 to 2011. Mr. Billings served as President of Cumberland Plateau Pipeline Company, a privately held company developing an ethane pipeline to serve the Marcellus Shale area, from 2009 until 2010. From 2008 to 2009, Mr. Billings served as Senior Vice President of Commercial for Crosstex Energy, Inc. and Crosstex Energy L.P., an independent midstream energy services master limited partnership and its parent corporation. In 1988, Mr. Billings joined MAPCO Inc., which merged with one of our subsidiaries in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business. Mr. Billings served as Senior Vice President - Corporate Strategic Development of the general partner of Pre-merger WPZ from January 2014 until the ACMP Merger. He has served as Senior Vice President - Corporate Strategic Development since the ACMP Merger, and as a director of the general partner of ACMP/WPZ since the ACMP Merger until February 2017.



Donald R. Chappel	Senior Vice President and Chief Financial Officer
	Age: 65
	Position held since 2003.
	Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Mr. Chappel has served as a director of the general partner of ACMP/WPZ since 2012 and as Chief Financial Officer of the general partner of ACMP/WPZ since December 31, 2014. Mr. Chappel has also served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel served as Chief Financial Officer and a director of the general partner of Pre-merger WPZ from 2005 until the ACMP Merger. Mr. Chappel was Chief Financial Officer from 2007 and a director from 2008 of the general partner of Williams Pipeline Partners L.P. (WMZ), until its merger with Pre-merger WPZ in 2010. Mr. Chappel is a director of SUPERVALU, Inc. (a grocery and pharmacy company).



John R. Dearborn	Senior Vice President — NGL & Petchem Services
	Age: 59
	Position held since 2013.
	Mr. Dearborn served as a senior leader for Saudi Basic Industries Corporation, a petrochemical company, from 2011 to 2013. From 2001 to 2011, Mr. Dearborn served in a variety of leadership positions with the Dow Chemical Company. Mr. Dearborn also worked for Union Carbide Corporation, prior to its merger with DOW, from 1981 to 2001 where he served in several leadership roles. Mr. Dearborn also served as Senior Vice President - NGL & Petchem Services of the general partner of Pre-merger WPZ from 2013 until the ACMP Merger and has served in that role for the general partner of ACMP/WPZ since the ACMP Merger.



Robyn L. Ewing	Senior Vice President and Chief Administrative Officer
	Age: 61
	Position held since 2008.
	From 2004 to 2008, Ms. Ewing was Vice President of Human Resources. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in 1998. Ms. Ewing began her career with Cities Service Company in 1976.



Rory L. Miller	Senior Vice President — Atlantic - Gulf
	Age: 56
	Position held since 2013.
	From 2011 until 2013, Mr. Miller was Senior Vice President - Midstream of Williams and the general partner of Pre-merger WPZ, acting as President of Williams’ midstream business. Mr. Miller was a Vice President of Williams’ midstream business from 2004 until 2011. Mr. Miller served as a director and Senior Vice-President - Atlantic-Gulf of the general partner of Pre-merger WPZ from 2011 until the ACMP Merger and has served in those roles for the general partner of ACMP/WPZ since the ACMP Merger. Mr. Miller has also served as a member of the Management Committee of Transco, since 2013.



Sarah C. Miller	Senior Vice President and General Counsel
	Age: 45
	Position held since 2015.
	Ms. Miller joined Williams in 2000, where she has served in a variety of legal leadership positions, including Vice President, Corporate Secretary and Assistant General Counsel for the company’s corporate secretary team, Senior Counsel for the company’s midstream business, and as Senior Attorney for the legal department’s business development team. She was named Senior Vice President and General Counsel on June 20, 2015. Prior to joining Williams, Ms. Miller was a litigation associate at Crowe & Dunlevy.



James E. Scheel	Senior Vice President — Northeast G&P
	Age: 52
	Position held since January 2014.
	From 2012 to 2014, Mr. Scheel served as Senior Vice President - Corporate Strategic Development of us and the general partner of Pre-merger WPZ. From 2011 until 2012, Mr. Scheel served as Vice President of Business Development for our midstream business. Mr. Scheel joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, our NGL business, and international operations. Mr. Scheel has served as a director and Senior Vice President - Northeast G&P of the general partner of ACMP/WPZ since the ACMP Merger, having previously served as a director of the general partner of ACMP/WPZ from 2012 to February 2014. Mr. Scheel served as a director of the general partner of Pre-merger WPZ from 2012 until the ACMP Merger.



John D. Seldenrust	Senior Vice President — Engineering Services
	Age: 52
	Position held since July 2015.
	Mr. Seldenrust served as Senior Vice President - Eastern Operations for us from January 2015 to July 2015, and for ACMP/WPZ from 2013 to July 2015. Mr. Seldenrust also previously served in a variety of operations and engineering leadership roles at ACMP and Chesapeake Energy from 2004 to August 2013. Prior to joining Chesapeake, Mr. Seldenrust held reservoir, production and facilities engineering positions with ARCO Oil & Gas, Vastar Resources and BP America.



Ted T. Timmermans	Vice President, Controller, and Chief Accounting Officer
	Age: 60
	Position held since 2005.
	Mr. Timmermans served as Assistant Controller of Williams from 1998 to 2005. Mr. Timmermans served as Vice President, Controller & Chief Accounting Officer of the general partner of Pre-merger WPZ until the ACMP Merger and has served in those roles for the general partner of ACMP/WPZ since the ACMP Merger. Mr. Timmermans served as Chief Accounting Officer of the general partner of WMZ from 2008 until its merger with Pre-merger WPZ in 2010.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 17, 2017, we had approximately 7,376 holders of record of our common stock. The high and low sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:



	High		Low		Dividend
2016
First Quarter	$	26.68	$	10.22	$	0.64
Second Quarter	23.89		14.60		0.64
Third Quarter	31.43		19.68		0.20
Fourth Quarter	32.21		27.35		0.20
2015
First Quarter	$	51.15	$	40.07	$	0.58
Second Quarter	61.38		46.28		0.59
Third Quarter	58.77		34.64		0.64
Fourth Quarter	44.51		20.95		0.64

Some of our subsidiaries’ borrowing arrangements may limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends. On February 20, 2017, our board of directors approved a regular quarterly dividend of $0.30 per share payable on March 27, 2017, representing a 50 percent increase from our previous quarterly dividend.

Performance Graph

Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index and the Bloomberg Americas Pipelines Index for the period of five fiscal years commencing January 1, 2012. The Bloomberg Americas Pipelines Index is composed of Enbridge, Inc., Inter Pipeline Ltd., Kinder Morgan, Inc., ONEOK, Inc., Pembina Pipeline Corp, Plains GP Holdings LP, Spectra Energy Corp, TransCanada Corp., Keyera Corp., AltaGas Ltd., and Williams. The graph below assumes an investment of $100 at the beginning of the period.



	2011	2012	2013	2014	2015	2016
The Williams Companies, Inc.	100.0	126.1	154.5	187.4	114.2	150.0
S&P 500 Index	100.0	115.9	153.4	174.3	176.8	197.8
Bloomberg Americas Pipelines Index	100.0	113.4	125.9	147.3	81.5	119.2

Item 6. Selected Financial Data

The following financial data at December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.



	2016			2015			2014		2013		2012
	(Millions, except per-share amounts)
Revenues (1)	$	7,499		$	7,360		$	7,637	$	6,860	$	7,486
Income (loss) from continuing operations (2)	(350		)	(1,314		)	2,335		679		929
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations (2)	(424		)	(571		)	2,110		441		723
Diluted earnings (loss) per common share:
Income (loss) from continuing operations (2)	(.57		)	(.76		)	2.91		.64		1.15
Total assets at December 31 (3)	46,835			49,020			50,455		27,065		24,248
Commercial paper and long-term debt due within one year at December 31 (4)	878			675			802		226		1
Long-term debt at December 31 (3)	22,624			23,812			20,780		11,276		10,656
Stockholders’ equity at December 31 (3)	4,643			6,148			8,777		4,864		4,752
Cash dividends declared per common share	1.680			2.450			1.9575		1.438		1.196

_________


(1)	Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian construction management services.


(2)	Income (loss) from continuing operations:


•	For 2016 includes an $873 million impairment of certain assets and a $430 million impairment of certain equity-method investments;


•	For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill;

•

For 2014 includes $2.5 billion pretax gain recognized as a result of remeasuring to fair value the equity-method investment we held before we acquired a controlling interest in ACMP, $246 million of insurance recoveries related to the 2013 Geismar Incident, and $154 million of cash received related to a contingency settlement. 2014 also includes $78 million of pretax equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs and $76 million of pretax acquisition, merger, and transition expenses related to our acquisition of ACMP;


•	For 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested.


(3)	The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMP (see Note 2 – Acquisitions) in third quarter as well as $1.9 billion of related debt issuances and $2.8 billion of debt issuances at WPZ. Additionally, we issued $3.4 billion of equity (see Note 15 – Stockholders' Equity).


(4)	The increases in 2014 and 2013 reflect borrowings under WPZ’s commercial paper program, which was initiated in 2013.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins. Our operations are located principally in the United States and are organized into the Williams Partners and Williams NGL & Petchem Services reportable segments. All remaining business activities are included in Other.

Williams Partners

Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses include interstate natural gas pipelines and pipeline joint project investments; and the midstream businesses provide natural gas gathering, treating, and processing services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services; an olefin production business, and is comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of December 31, 2016, we owned approximately 60 percent of the interests in WPZ, including the interests of the general partner, which were wholly owned by us, and IDRs.

Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. As of December 31, 2016, Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,230 Tbtu of natural gas and peak-day delivery capacity of approximately 15.5 MMdth of natural gas.

Williams Partners' midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) NGL fractionation, storage and transportation; (3) crude oil production handling and transportation; and (4) olefins production. (See Geismar Olefins Facility Monetization below.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica Shale plays as well as the Mid-Continent region.

The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 41 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

The midstream businesses previously included our Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and investing in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the Gulf Coast Region, and areas of increasing natural gas demand.

Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion

or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

Williams NGL & Petchem Services

Williams NGL & Petchem Services includes certain domestic olefins pipeline assets as well as the previously owned Canadian assets which included a liquids extraction plant near Fort McMurray, Alberta, that began operations in March 2016 and a propane dehydrogenation facility under development in Canada. In September 2016, these Canadian operations were sold. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.

Dividends

In December 2016, we paid a regular quarterly dividend of $0.20 per share. On February 20, 2017, our board of directors approved a regular quarterly dividend of $0.30 per share payable on March 27, 2017, representing a 50 percent increase from our previous quarterly dividend.

Overview

Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2016, increased $147 million compared to the year ended December 31, 2015, reflecting the absence of certain goodwill impairments, lower impairments of equity-method investments, an increase in olefins margins associated with our Geismar plant, decreases in operating and maintenance expenses, and higher equity earnings. These favorable changes were partially offset by an unfavorable change in net income attributable to noncontrolling interests driven primarily by higher WPZ income as well as the impact of reduced incentive distributions from WPZ associated with the termination of the WPZ Merger Agreement. The favorable changes were also partially offset by increased impairment charges and loss on sale associated with our Canadian operations, lower insurance recoveries, as well as higher interest incurred. See additional discussion in Results of Operations.

Acquisition of Additional Interests in Appalachia Midstream Investments

In February, 2017, we announced agreements to acquire additional interests in two Marcellus Shale gathering systems within Williams Partners’ Appalachia Midstream Investments in exchange for equity-method investment interests in DBJV and the Ranch Westex gas processing plant, both currently reported within the Williams Partners segment. We also expect to receive a total of $200 million in cash as part of the agreements subject to customary closing conditions and purchase price adjustments. The transactions are expected to close in late first-quarter or early second-quarter 2017.

Financial Repositioning

the monetization process of Geismar and the other select assets. As we pursue these other asset monetizations, it is possible that we may incur impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.

Energy Transfer Merger Agreement

On June 29, 2016, Energy Transfer provided us written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.

Termination of WPZ Merger Agreement

On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).

On September 28, 2015, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.

Organizational Realignment

Information in this report has generally been prepared to be consistent with the reportable segment presentation in our consolidated financial statement in Part II, Item 8 of this document. These segments are discussed in further detail in the following sections.

Williams Partners

Northwest Pipeline rate case

On January 23, 2017, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for new rates. The new rates become effective January 1, 2018, and are not expected to materially affect our trend of earnings. Pursuant to this agreement, Northwest Pipeline can file for new rates to be effective after October 1, 2018, and must file a general rate case for new rates to become effective no later than January 1, 2023.

Geismar olefins facility monetization

In September 2016, Williams Partners announced the initiation of an ongoing process to explore monetization of its ownership interest in the Geismar, Louisiana, olefins plant and complex, consistent with our strategy to narrow our focus and allocate capital to our natural gas–focused business.

Sale of Canadian operations

In September 2016, we completed the sale of our Canadian operations for total consideration of $1.02 billion. We recognized an impairment charge of $747 million during the second quarter of 2016 related to these operations and an additional loss of $66 million upon completion of the sale. (See Note 3 – Divestiture.)

Barnett Shale and Mid-Continent contract restructurings

In August 2016, Williams Partners conditionally committed to execute a new gas gathering agreement in the Barnett Shale. The agreement was executed in the fourth quarter of 2016, in conjunction with our existing customer, Chesapeake Energy Corporation, closing the sale of its Barnett Shale properties to another producer. That other producer, which has an investment grade credit rating, is now our customer under the new gas gathering agreement. The restructured agreement provided a $754 million up-front cash payment to us primarily in exchange for eliminating future minimum volume commitments. The restructured agreement also provides for revised gathering rates. Based on current commodity price assumptions at the time of the agreement, we generally expect the up-front cash proceeds and the ongoing cash flows generated by gathering services, to represent equivalent net present value of cash flows as compared to expected performance under the existing agreement. Additionally, Williams Partners agreed to a revised contract in the Mid-Continent region, also with Chesapeake Energy Corporation. The revised contract was executed in the third quarter of 2016 and provided an up-front cash payment to us of $66 million primarily in exchange for changing from a cost of service contract to fixed-fee terms. The majority of the up-front cash proceeds from both agreements were recognized as deferred revenue and will be amortized into income in future periods. In the near term, we do not expect that our trend of reported results will be significantly impacted by the effect of the discount associated with the up-front cash proceeds relative to the original minimum volume commitments and reduced gathering rates. It was anticipated that both agreements would reduce customer concentration risk and provide support to realize additional drilling and improved volumes in these regions.

Powder River basin contract restructuring

In October 2016, in conjunction with our partner in the Bucking Horse natural gas processing plant and Jackalope Gas Gathering System, we announced an agreement with Chesapeake Energy Corporation to restructure gathering and processing contracts in the Powder River basin. The restructured contracts became effective in January 2017 and replaced the previous cost-of-service arrangement with MVCs in the near-term such that we do not expect that our near-term trend of reported results will be significantly impacted by the restructured terms.

Rock Springs expansion

In August 2016, the Rock Springs expansion was placed into service. The project expanded Transco’s existing natural gas transmission system from New Jersey to a generation facility in Maryland and increased capacity by 192 Mdth/d.

Gulf Trace expansion

In February 2017, the Gulf Trace expansion was placed into service. The project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. It is expected to increase capacity by 1,200 Mdth/d.

Redwater expansion

In March 2016, we completed the expansion of our Redwater facilities in support of a long-term agreement to provide gas processing services to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta. The expanded Redwater facility receives NGL/olefins mixtures from the second bitumen upgrader and fractionates the mixtures into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. We sold these operations in September 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

Williams NGL & Petchem Services

Horizon liquids extraction plant

In March 2016, we completed a new liquids extraction plant near Fort McMurray, Alberta. The Boreal pipeline was extended to enable transportation of the NGL/olefins mixture from the new liquids extraction plant to Williams Partners’ expanded Redwater facilities. The plant increased the amount of NGLs produced in Canada to a total of approximately 40 Mbbls/d. To mitigate ethane price risk associated with our processing services, we had a long-term agreement with a minimum price for ethane sales to a third-party customer. We sold these operations in September 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)

Commodity Prices

NGL per-unit margins were approximately 7 percent lower in 2016 compared to the same period of 2015. Following a sharp decline in late 2014 to early 2015, total NGL margins have remained somewhat consistent in 2015 and 2016. While 2014 and 2015 reflect limited ethane recoveries, we have seen an increase in ethane production during 2016.

NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.

The potential impact of commodity prices on our business is further discussed in the following Company Outlook.

Company Outlook

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.

Our business plan for 2017 includes the previously announced agreement with WPZ to permanently waive our incentive distribution rights in exchange for WPZ common units as well as our private purchase of $2.1 billion newly issued WPZ commits units. We expect to increase our dividend to $0.30 per share, or $1.20 annually, beginning in the first quarter of 2017. Our business plan also includes previously discussed asset monetizations, which include our ownership interest in the Geismar olefins facility as well as other select assets that are not core to our strategy. The monetizations are expected to yield after-tax proceeds of greater than $2.0 billion. For WPZ, these transactions are expected to improve its cost of capital, remove its need to access the public equity markets for the next several years, enhance growth, and provide for debt reduction, solidifying WPZ as an attractive financing vehicle. The transactions are also expected to facilitate a reduction of our parent-level debt and provides for dividend growth flexibility, while retaining strategic and financing flexibility.

Our growth capital and investment expenditures in 2017 are expected to total $2.1 billion to $2.8 billion. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based gathering and processing projects, as well as the previously discussed sale of our Canadian operations and the planned monetization of the Geismar olefins facility, fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. Current forward market prices indicate a slightly more favorable energy commodity price environment in 2017 as compared to 2016, including higher natural gas and NGL prices. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering volumes. Although there has been some improvement, the credit profiles of certain of our producer customers remain challenged. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.

In 2017, our operating results will include increases from our fee-based businesses recently placed in service or expected to be placed in service in 2017 primarily along the Transco system, a full year benefit of expanded capacity on our Gulfstar FPS™, and lower general and administrative expenses due to cost reduction initiatives and asset monetizations. We expect overall gathering and processing volumes to remain steady in 2017 and increase thereafter to meet the growing demand for natural gas and natural gas products.

Potential risks and obstacles that could impact the execution of our plan include:


•	Opposition to infrastructure projects, including the risk of delay in permits needed for our projects;


•	Unexpected significant increases in capital expenditures or delays in capital project execution;


•	Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;


•	Inability to execute or delay in completing planned asset monetizations;


•	Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices and margins;


•	General economic, financial markets, or further industry downturn, including increased interest rates;


•	Physical damages to facilities, including damage to offshore facilities by named windstorms;


•	Reduced availability of insurance coverage;


•	Lower than expected distributions from WPZ.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.

Expansion Projects

Our ongoing major expansion projects include the following:

Williams Partners

Eagle Ford

We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of new facilities, well connections, and gathering pipeline to the existing systems.

Oak Grove Expansion

We plan to expand our processing capacity at our Oak Grove facility by adding a second 200 MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2020.

Gathering System Expansion

We will continue to expand the gathering systems in the Marcellus and Utica Shale regions that are needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.

Constitution Pipeline

In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC’s denial of the certification and filed an action in federal court seeking a declaration that the State of New York’s authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. (See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.) We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 126-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the target in-service date has been revised to as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded.

Garden State

In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We plan to place the initial phase of the project into service during the third quarter of 2017 and the remaining portion in the second quarter of 2018, assuming timely receipt of all necessary regulatory approvals.

Norphlet Project

In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2020.

Hillabee

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a proposed new interconnection with the Sabal Trail project in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We plan to place the initial phase of the project into service concurrent with the in-service date of the Sabal Trail project, which is planned to occur as early as the second quarter of 2017. The in-service date of the second phase of the project is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.

In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met. The first $80 million payment was received in March 2016 and the second installment was received in September 2016. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.

New York Bay Expansion

In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We plan to place the project into service during the fourth quarter of 2017, and it is expected to increase capacity by 115 Mdth/d.

Atlantic Sunrise

In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We expect to place a portion of the project facilities into service during the second half of 2017 and are targeting a full in-service during mid-2018, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,700 Mdth/d.

Virginia Southside II

In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey and Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan

to place the project into service during the fourth quarter of 2017 and it is expected to increase capacity by 250 Mdth/d.

Dalton

In August 2016, we obtained approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017 and it is expected to increase capacity by 448 Mdth/d.

Gulf Connector

In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases, with the initial phase of the project expected to be in service during the second half of 2018 and the remaining phase in 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

Williams NGL & Petchem Services

Gulf Coast NGL and Olefin Infrastructure Expansion

Certain previously acquired liquids pipelines in the Gulf Coast region are expected to be combined with an organic build-out of several projects to expand our petrochemical services in that region. The projects include the construction and commissioning of pipeline systems capable of transporting various purity natural gas liquids and olefins products in the Gulf Coast region. In response to the current conditions in the midstream industry, we are slowing the pace of development and may seek partners for these projects.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Pension and Postretirement Obligations

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.



	Benefit Cost						Benefit Obligation
	One- Percentage- Point Increase			One- Percentage- Point Decrease			One- Percentage- Point Increase			One- Percentage- Point Decrease
	(Millions)
Pension benefits:
Discount rate	$	(9	)	$	10		$	(130	)	$	154
Expected long-term rate of return on plan assets	(13		)	13			—			—
Rate of compensation increase	3			(2		)	9			(7		)
Other postretirement benefits:
Discount rate	1			1			(21		)	25
Expected long-term rate of return on plan assets	(2		)	2			—			—
Assumed health care cost trend rate	—			—			6			(5		)

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which include an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets, which are weighted toward domestic and international equity securities. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.

In 2016, the benefit plans’ assets outperformed their respective benchmarks for fixed income strategies, but generally underperformed the respective benchmarks for equity strategies. While the 2016 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.85 percent in 2016. The 2016 actual return on plan assets for our pension plans was approximately 7.5 percent. The 10-year average rate of return on pension plan assets through December 2016 was approximately 3.7 percent.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.

The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and cost to increase.

The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.

Equity-Method Investments

At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and determined that no impairment was necessary. We also entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes.

During the fourth quarter of 2016, these discussions led to negotiations with the system operator to exchange our interest in DBJV and another equity-method investment in the Permian basin (Ranch Westex) for its interests in certain gathering systems in the Northeast and cash. We already hold partial interests in these Northeast gathering systems through our Appalachia Midstream Investments. As previously discussed, we reached agreements for such transactions in February 2017.

As part of the preparation of our year-end financial statements, we evaluated the carrying amounts of our investments in DBJV, Ranch Westex and these certain gathering systems within our Appalachia Midstream Investments for impairment. We also evaluated other equity-method investments within the Northeast area for impairment as of December 31, 2016, including other gathering systems within our Appalachia Midstream Investments and our investment in UEOM. Our impairment evaluations utilized an income approach, but also considered the fair values indicated by the previously described transaction. The estimated fair value of our investment in DBJV exceeded its carrying value and no impairment was necessary. Based on the fair value of the consideration expected to be received, we currently expect to recognize a gain upon consummation of the previously described exchange transaction in 2017.

We estimated the fair value of our Appalachia Midstream Investments and UEOM using an income approach with discount rates ranging from 10.2 percent to 12.5 percent and also considered the value implied by the previously described transactions as applicable. For certain gathering systems within our Appalachia Midstream Investments, the fair value was determined to be less than our carrying value, resulting in an other-than-temporary impairment charge of $294 million. No impairment was necessary for other gathering systems within our Appalachia Midstream Investments or our investment in UEOM. For those investments evaluated for which no impairment was required, our estimate of fair value exceeded our carrying value by amounts ranging from approximately 2.5 percent to 7.5 percent. We estimate that an increase in the discount rate utilized of 50 basis points would have resulted in an additional impairment charge of approximately $45 million. We also recorded an additional impairment of $24 million related to our interest in Ranch Westex.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.

At December 31, 2016, our Consolidated Balance Sheet includes approximately $6.7 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.

If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:


•	A significant or sustained decline in the market value of an investee;


•	Lower than expected cash distributions from investees;


•	Significant asset impairments or operating losses recognized by investees;


•	Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;


•	Significant delays in or failure to complete significant growth projects of investees.

Constitution Pipeline Capitalized Project Costs

As of December 31, 2016, Property, plant, and equipment – net in our Consolidated Balance Sheet includes approximately $381 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. In December 2014, we received approval from the FERC to construct and operate this jointly owned pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law.

As a result of the denial by the NYSDEC, we evaluated the capitalized project costs for impairment as of March 31, 2016, and as of December 31, 2016, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYSDEC and construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2016. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



	Years Ended December 31,
	2016			$ Change from 2015*	% Change from 2015*		2015			$ Change from 2014*	% Change from 2014*		2014
	(Millions)
Revenues:
Service revenues	$	5,171		+7	—	%	$	5,164		+1,048	+25	%	$	4,116
Product sales	2,328			+132	+6	%	2,196			-1,325	-38	%	3,521
Total revenues	7,499						7,360						7,637
Costs and expenses:
Product costs	1,725			+54	+3	%	1,779			+1,237	+41	%	3,016
Operating and maintenance expenses	1,580			+75	+5	%	1,655			-163	-11	%	1,492
Depreciation and amortization expenses	1,763			-25	-1	%	1,738			-562	-48	%	1,176
Selling, general, and administrative expenses	723			+18	+2	%	741			-80	-12	%	661
Impairment of goodwill	—			+1,098	+100	%	1,098			-1,098	NM		—
Impairment of certain assets	873			-664	NM		209			-157	NM		52
Net insurance recoveries – Geismar Incident	(7		)	-119	-94	%	(126		)	-106	-46	%	(232		)
Other (income) expense – net	142			-102	NM		40			-137	NM		(97		)
Total costs and expenses	6,799						7,134						6,068
Operating income (loss)	700						226						1,569
Equity earnings (losses)	397			+62	+19	%	335			+191	+133	%	144
Gain on remeasurement of equity-method investment	—			—	—	%	—			-2,544	-100	%	2,544
Impairment of equity-method investments	(430		)	+929	+68	%	(1,359		)	-1,359	NM		—
Other investing income (loss) – net	63			+36	+133	%	27			-16	-37	%	43
Interest expense	(1,179		)	-135	-13	%	(1,044		)	-297	-40	%	(747		)
Other income (expense) – net	74			-28	-27	%	102			+71	NM		31
Income (loss) from continuing operations before income taxes	(375		)				(1,713		)				3,584
Provision (benefit) for income taxes	(25		)	-374	-94	%	(399		)	+1,648	NM		1,249
Income (loss) from continuing operations	(350		)				(1,314		)				2,335
Income (loss) from discontinued operations	—			—	—	%	—			-4	-100	%	4
Net income (loss)	(350		)				(1,314		)				2,339
Less: Net income (loss) attributable to noncontrolling interests	74			-817	NM		(743		)	+968	NM		225
Net income (loss) attributable to The Williams Companies, Inc.	$	(424	)				$	(571	)				$	2,114

_______


*	+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

2016 vs. 2015

Service revenues increased slightly primarily due to expansion projects placed in service in 2015 and 2016, partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes in the Barnett Shale and Anadarko basin.

Product sales increased primarily due to higher olefin sales reflecting increased volumes at our Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by a decrease from our other olefin operations associated with lower volumes and per-unit sales prices. Product sales also reflect higher marketing revenues associated with higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes, and crude oil prices.

The decrease in Product costs includes lower olefin feedstock purchases and lower costs associated with other product sales, partially offset by higher marketing purchases primarily due to the same factors that increased marketing sales. The decline in olefin feedstock purchases is primarily associated with lower per-unit feedstock costs and volumes at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our Geismar plant reflecting increased volumes resulting from higher production levels in 2016.

Operating and maintenance expenses decreased primarily due to lower labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as the absence of ACMP transition-related costs recognized in 2015. These decreases are partially offset by $16 million of severance and related costs recognized in 2016 and higher pipeline testing and general maintenance costs at Transco.

Depreciation and amortization expenses increased primarily due to depreciation on new assets placed in service, including Transco pipeline projects, partially offset by lower depreciation related to Canadian operations sold in 2016.

Selling, general, and administrative expenses (SG&A) decreased primarily due to lower merger and transition costs associated with the ACMP merger and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts. These decreases were partially offset by certain project development costs associated with the Canadian PDH facility that we began expensing in 2016, as well as $26 million of severance and related costs recognized in 2016 and $17 million of higher costs associated with our evaluation of strategic alternatives.

Impairment of goodwill decreased due to the absence of a 2015 impairment charge associated with certain goodwill. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Impairment of certain assets reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets, and other assets. Impairments recognized in 2015 relate primarily to previously capitalized development costs and surplus equipment write-downs. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Net insurance recoveries – Geismar Incident changed unfavorably reflecting the receipt of $126 million of insurance proceeds in the second quarter of 2015, as compared to the receipt of $7 million of proceeds in the fourth quarter of 2016.

The unfavorable change in Other (income) expense – net within Operating income (loss) includes a loss on the sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we discontinued capitalization of these costs in April 2016, and an unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations, partially offset by a $10 million gain on the sale of idle pipe in 2016.

Operating income (loss) changed favorably primarily due to the absence of a goodwill impairment in 2015, higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger and integration of ACMP, and lower costs and expenses primarily associated with cost containment efforts.

These favorable changes are partially offset by impairments and loss on sale of certain assets in 2016, a decrease in insurance proceeds received, expensed Canadian PDH facility project development costs, and higher depreciation expenses related to new projects placed in service.

Equity earnings (losses) changed favorably primarily due to a $30 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, OPPL, Laurel Mountain, and DBJV improved $16 million, $11 million, and $10 million, respectively.

Impairment of equity-method investments reflects 2016 impairment charges associated with our Appalachia Midstream Investments, DBJV, and Laurel Mountain equity-method investments, while the 2015 impairment charges relate to our equity-method investments in Appalachia Midstream Investments, DBJV, UEOM, and Laurel Mountain. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Other investing income (loss) – net changed favorably due to a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments and higher interest income associated with a receivable related to the sale of certain former Venezuela assets. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Interest expense increased due to higher Interest incurred of $99 million primarily attributable to new debt issuances in 2016 and 2015 and lower Interest capitalized of $36 million primarily related to construction projects that have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to a decrease in allowance for equity funds used during construction (AFUDC) due to decreased spending on Constitution and the absence of a $14 million gain on early debt retirement in 2015.

Provision (benefit) for income taxes changed unfavorably primarily due to a decrease in pretax loss in 2016. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the impact of reduced incentive distributions from WPZ associated with the termination of the WPZ Merger Agreement, and the absence of the accelerated amortization of a beneficial conversion feature from the first quarter of 2015. These changes are partially offset by a favorable change primarily related to our partners’ share of Constitution project development costs in 2016.

2015 vs. 2014

Service revenues increased primarily due to additional revenues associated with a full year of ACMP operations in 2015, increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and an increase in Transco’s natural gas transportation fees due to new projects placed in service in 2014 and 2015. Revenues from operations associated with our acquisition of ACMP and the northeast region also increased due to higher volumes related to new well connects. A decrease in Canadian construction management revenues, reflecting a shift to internal customer construction projects, partially offset these increases.

Product sales decreased due to a decrease in marketing revenues primarily associated with lower prices across all products, partially offset by higher non-ethane volumes, and a decrease in revenues from our equity NGLs reflecting lower NGL prices, partially offset by higher NGL volumes. Product sales also decreased due to lower olefin sales from other olefin operations associated with lower per-unit sales prices, partially offset by higher volumes. These decreases are partially offset by an increase in olefin sales primarily due to resuming our Geismar operations during 2015.

Product costs decreased due to a decrease in marketing purchases primarily associated with lower per-unit costs, partially offset by higher non-ethane volumes, and a decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices, partially offset by higher volumes. Product costs also decreased

due to lower feedstock purchases in our other olefin operations primarily due to lower per-unit feedstock costs across all products as well as lower per-unit costs, partially offset by significantly higher volumes in 2015. These decreases are partially offset by an increase in olefin feedstock purchases primarily associated with resuming our Geismar operations.

Operating and maintenance expenses increased primarily due to new expenses associated with operations acquired in our acquisition of ACMP, increased growth of operating activity in certain areas, increased maintenance and repair expenses, and the return to operations of the Geismar plant. These increases are partially offset by a decrease in Canadian construction management expenses that reflect a shift to internal customer construction projects.

Depreciation and amortization expenses increased primarily due to new expenses associated with operations acquired in our acquisition of ACMP and from depreciation on new projects placed in service, including Gulfstar One and the Geismar expansion.

SG&A increased primarily due to administrative expenses associated with operations acquired in our acquisition of ACMP, including $31 million higher ACMP merger and transition-related costs, partially offset by the absence of $16 million of acquisition costs incurred in 2014. In addition, 2015 includes $32 million of costs associated with our evaluation of strategic alternatives. These increases are partially offset by the absence of $18 million of project development costs incurred in 2014 related to the Bluegrass Pipeline reflecting 100 percent of such costs. The 50 percent noncontrolling interest share of these costs are presented in Net income (loss) attributable to noncontrolling interests.

Impairment of goodwill reflects a 2015 impairment charge associated with certain goodwill. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Impairment of certain assets relate primarily to 2015 impairments of previously capitalized development costs and surplus equipment write-downs. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Net insurance recoveries – Geismar Incident changed unfavorably primarily due to the receipt of $126 million of insurance recoveries in 2015 as compared to the receipt of $246 million of insurance recoveries in 2014.

Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to the absence of $154 million of cash proceeds received in 2014 related to a contingency settlement gain and the absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release. (See Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

Operating income (loss) changed unfavorably primarily due to a 2015 impairment of goodwill, higher impairments of certain assets, higher depreciation, operating, and maintenance expenses related to construction projects placed in service and the start-up of the Geismar plant, $229 million lower NGL margins driven by lower prices, lower insurance recoveries related to the Geismar Incident, higher costs related to the merger and integration of ACMP into WPZ, and 2015 strategic alternative expenses. These decreases were partially offset by increased service revenues related to construction projects placed in service, $116 million higher olefin margins primarily due to our Geismar plant that returned to operations in 2015, and contributions from the operations acquired in our acquisition of ACMP.

Equity earnings (losses) changed favorably primarily due to the absence of equity losses from Bluegrass Pipeline and Moss Lake in 2014 and due to contributions from investments acquired in our acquisition of ACMP. In addition, equity earnings at Discovery increased $76 million primarily related to the completion of the Keathley Canyon Connector in early 2015. These changes were partially offset by $33 million of losses associated with our share of impairments recognized at equity investees in 2015. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Gain on remeasurement of equity-method investment reflects the 2014 gain recognized as a result of remeasuring to fair value the equity-method investment that we held before we acquired a controlling interest in ACMP. (See Note 2 – Acquisitions of Notes to Consolidated Financial Statements.)

Impairment of equity-method investments reflects 2015 impairment charges associated with certain equity-method investments. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Other investing income (loss) – net changed unfavorably primarily due to lower interest income associated with a receivable related to the sale of certain former Venezuela assets.

Interest expense increased due to a $230 million increase in Interest incurred primarily due to new debt issuances in 2014 and 2015 and interest expense associated with debt assumed in conjunction with our acquisition of ACMP. This increase was partially offset by lower interest due to 2015 debt retirements and the absence of a $9 million transaction-related financing fee incurred in the second quarter of 2014 related to our acquisition of ACMP. In addition, Interest capitalized decreased $67 million primarily related to construction projects that have been placed into service. (See Note 2 – Acquisitions and Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

Other income (expense) – net below Operating income (loss) changed favorably primarily due to a $43 million benefit related to an increase in AFUDC associated with an increase in spending on various Transco expansion projects and Constitution, a $14 million gain on early debt retirement in April 2015, and a $9 million contingency gain settlement.

Provision (benefit) for income taxes changed favorably primarily due to lower pretax income in 2015. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.

The favorable change in Net income (loss) attributable to noncontrolling interests related to our investment in WPZ is primarily due to lower operating results at WPZ, our increased percentage of limited partner ownership of WPZ, and the impact of increased income allocated to the WPZ general partner, held by us, associated with IDRs. These changes are partially offset by an unfavorable change related to our investment in Gulfstar One associated with its start up in 2014.

Year-Over-Year Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 19 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Williams Partners



	Years Ended December 31,
	2016			2015			2014
	(Millions)
Service revenues	$	5,173		$	5,135		$	3,888
Product sales	2,318			2,196			3,521
Segment revenues	7,491			7,331			7,409

Product costs	(1,728		)	(1,779		)	(3,016		)
Other segment costs and expenses	(2,203		)	(2,229		)	(1,760		)
Net insurance recoveries – Geismar Incident	7			126			232
Impairment of certain assets	(457		)	(145		)	(52		)
Proportional Modified EBITDA of equity-method investments	754			699			431
Williams Partners Modified EBITDA	$	3,864		$	4,003		$	3,244

NGL margin	$	169		$	159		$	388
Olefin margin	337			226			110

2016 vs. 2015

Modified EBITDA decreased primarily due to higher impairments, lower insurance recoveries associated with the Geismar Incident, and loss on sale associated with our Canadian operations. These decreases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower segment costs and expenses, and higher earnings related to our equity-method investments, including the completion of the Keathley Canyon Connector at Discovery in the first quarter of 2015. Additionally, higher marketing margins, higher service revenues related to projects placed in service, and higher NGL margins improved Modified EBITDA.

The increase in Service revenues is primarily due to a $79 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016 and a $31 million transportation and fractionation revenue increase associated with Williams NGL & Petchem’s Horizon liquids extraction plant in Canada. The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes primarily in the Barnett Shale and Anadarko basin and a $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016.

Product sales increased primarily due to:

•

A $94 million increase in olefin sales comprised of a $170 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $76 million decrease from our other olefin operations. The increase at Geismar includes $153 million associated with increased volumes as a result of the plant operating at higher production levels in 2016 than when production resumed in March 2015 following the Geismar Incident and $17 million primarily associated with higher ethylene per-unit sales prices. The decrease in other olefin sales includes a $14 million reduction due to the absence of our former Canadian operations in the fourth quarter of 2016, as well as lower volumes and lower per-unit sales prices within our other olefin operations;


•	A $70 million increase in marketing revenues primarily due to higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes and crude oil prices (partially offset in marketing purchases);


•	A $6 million increase in revenues from our equity NGLs due to a $10 million increase associated with higher volumes, partially offset by a $4 million decrease associated with lower NGL prices;


•	A $39 million decrease in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA.

The decrease in Product costs includes:


•	A $39 million decrease in system management gas costs (offset in Product sales);

•

A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases at our other olefins operations, partially offset by $61 million of higher purchases due primarily to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at our other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;


•	A $4 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a decrease of $13 million due to lower natural gas prices, partially offset by a $9 million increase associated with higher volumes;


•	Lower costs associated with various other products, primarily condensate;


•	A $22 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate.

The decrease in Other segment costs and expenses is primarily due to lower operating costs and general and administrative expenses reflecting decreases in primarily labor-related and outside services costs resulting from our first-quarter 2016 workforce reductions and ongoing cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as $43 million of lower ACMP Merger and transition-related expenses. Other items partially offsetting these decreases are as follows:


•	$34 million increase related to the 2016 loss on sale of our Canadian operations;


•	$37 million increase for severance and related costs associated with workforce reductions incurred in the first quarter of 2016 and the organizational realignment in the fourth quarter of 2016;


•	$28 million higher project development costs at Constitution as we discontinued capitalization of development costs related to this project beginning in April 2016;


•	$22 million higher contract services for pipeline testing and general maintenance at Transco;


•	$20 million unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations;


•	$19 million unfavorable change in AFUDC associated with a decrease in spending on Constitution;


•	The absence of a $14 million gain recognized in second-quarter 2015 resulting from the early retirement of certain debt.

Net insurance recoveries – Geismar Incident decreased reflecting $7 million of insurance proceeds received in 2016 compared to $126 million received in 2015.

Impairment of certain assets increased primarily due to 2016 impairments of $341 million associated with our Canadian operations and $63 million associated with certain Mid-Continent gathering assets as well as impairments or write-downs of other certain assets that may no longer be in use or are surplus in nature, partially offset by the absence of 2015 impairments of $94 million associated with previously capitalized project development costs for a gas processing plant and $20 million associated with certain surplus equipment within our Ohio Valley Midstream business. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a $30 million increase from Discovery primarily associated with higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II contributed a $20 million increase resulting from higher volumes due to assets placed into service in 2015, OPPL contributed a $16 million increase primarily due to higher transportation volumes and lower expenses, and UEOM contributed an $11 million increase primarily associated with an increase in our ownership percentage. These increases were partially offset by an $29 million decrease from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by lower impairments and higher volumes.

2015 vs. 2014

Modified EBITDA increased primarily due to the acquisition of ACMP during the third quarter of 2014 and increased fee revenue associated with contributions from new and expanded facilities, including Gulfstar One during the fourth quarter of 2014, in addition to resuming our Geismar operations and contributions related to the completion of the Keathley Canyon Connector at Discovery. Partially offsetting these increases to Modified EBITDA is a decrease in

NGL margins as a result of a significant decline in commodity prices beginning in the fourth quarter of 2014 and lower insurance recoveries related to the Geismar Incident.

The increase in Service revenues is primarily due to $810 million additional revenues associated with a full year of ACMP operations in 2015 which includes a $72 million increase in the minimum volume commitment fees, $223 million in increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and a $155 million increase in Transco’s natural gas transportation fees due to new projects placed in service in 2015 and 2014. Additionally, service revenues reflect higher fees associated with increased volumes and additional contributions in the Northeast. Higher revenues in the Northeast include expanded gathering operations and processing, fractionation and transportation operations, contributing $59 million and $27 million of additional fees, respectively.

The decrease in Product sales includes:


•	A $1,173 million decrease in marketing revenues primarily associated with lower prices across all products, partially offset by higher non-ethane volumes (more than offset in marketing purchases);


•	A $324 million decrease in revenues from our equity NGLs reflecting a decrease of $365 million due to lower NGL prices, partially offset by a $41 million increase associated with higher NGL volumes;


•	A $41 million decrease in revenues primarily due to lower condensate prices;


•	A $214 million increase in olefin sales primarily due to $298 million in higher sales from our Geismar plant that returned to operation, partially offset by an $84 million decrease from our other olefin operations due to lower sales prices, partially offset by higher volumes across all products, particularly propylene.

The decrease in Product costs includes:


•	A $1,219 million decrease in marketing purchases primarily due to a decrease in non-ethane per-unit cost (substantially offset in marketing revenues);


•	A $95 million decrease in the natural gas purchases associated with the production of equity NGLs reflecting a decrease of $126 million due to lower natural gas prices, partially offset by a $31 million increase associated with higher volumes;


•	A $20 million decrease in costs primarily due to lower gas prices;


•	A $98 million increase in olefin feedstock purchases is comprised of $127 million in higher purchases due to increased volumes at our Geismar plant as it returned to operation, partially offset by $29 million in lower other olefin operations feedstock purchases primarily due to lower per-unit feedstock costs, partially offset by higher volumes across most products, particularly propylene.

The increase in Other segment costs and expenses includes:


•	An increase for new expenses associated with operations associated with the acquisition of ACMP;


•	The absence of $154 million of cash received in the fourth quarter of 2014 associated with the resolution of a contingent gain related to claims arising from the purchase of a business in a prior period (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);


•	A $16 million increase in operating expense due to the Geismar plant returning to operation in 2015;


•	The absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release.

The decrease in Net insurance recoveries – Geismar Incident is primarily due to the 2015 receipt of $126 million of insurance proceeds compared to $246 million received in 2014, partially offset by the absence of covered insurable

expenses in excess of our retentions (deductibles) related to the Geismar Incident in 2015 compared to $14 million in 2014.

Impairment of certain assets increased primarily due to a 2015 $94 million impairment charge associated with previously capitalized project development costs for a gas processing plant. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a full year contribution of $160 million from investments associated with the acquisition of ACMP and a $103 million increase from Discovery associated with higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II increased $21 million resulting from assets placed into service in 2014 and 2015, partially offset by the absence of business interruption insurance proceeds received in the prior year, and an $11 million decrease at Laurel Mountain. The decrease at Laurel Mountain was primarily due to $13 million of impairments and lower gathering fees due to lower gathering rates indexed to natural gas prices, partially offset by 24 percent higher volumes and an increase in our ownership percentage compared to the prior year.

Williams NGL & Petchem Services



	Years Ended December 31,
	2016			2015			2014
	(Millions)
Service revenues	$	2		$	2		$	—
Product sales	26			—			—
Segment revenues	28			2			—

Product costs	(13		)	—			—
Other segment costs and expenses	(139		)	(85		)	(37		)
Impairment of certain assets	(416		)	—			—
Proportional Modified EBITDA of equity-method investments	—			—			(78		)
Williams NGL & Petchem Services Modified EBITDA	$	(540	)	$	(83	)	$	(115	)

2016 vs. 2015

The unfavorable change in Modified EBITDA is primarily due to the 2016 impairment and subsequent loss on disposal of our Canadian operations as well as the expensing of certain development costs associated with the Canadian PDH facility, partially offset by the absence of the 2015 write-off of previously capitalized project development costs for an olefins pipeline project.

The increase in Product sales and Product costs is primarily due to the Horizon liquids extraction plant coming online in March 2016 until it was sold in September 2016.

The unfavorable change in Other segment costs and expenses is primarily due to $61 million of certain project development costs associated with the Canadian PDH facility that we began expensing in 2016. Additionally, the unfavorable change includes $33 million of transportation and fractionation fees associated with our new Horizon volumes and a $32 million loss on the sale of our Canadian operations in September 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.) The unfavorable change in Other segment costs and expenses is partially offset by a $10 million gain on the sale of unused pipe in 2016 and the absence of the $64 million write-off of previously capitalized project development costs for an olefins pipeline project in 2015. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

The unfavorable change in Impairment of certain assets primarily reflects the 2016 impairment of our Canadian operations and an $8 million impairment of idle pipe. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

2015 vs. 2014

The favorable change in Modified EBITDA is primarily due to the absence of our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake, as well as costs incurred in 2014 relating to the development of the Bluegrass Pipeline, partially offset by the 2015 write-off of previously capitalized project development costs for an olefins pipeline project.

Other segment costs and expenses increased primarily due to the $64 million write-off of previously capitalized project development costs for an olefins pipeline project in 2015, partially offset by the absence of $18 million of project development costs incurred in 2014 relating to the Bluegrass Pipeline.

The favorable change in Proportional Modified EBITDA of equity-method investments is primarily due to the absence of our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake.

Other



	Years Ended December 31,
	2016			2015			2014
	(Millions)
Other Modified EBITDA	$	(2	)	$	(29	)	$	103

2016 vs. 2015

Modified EBITDA improved primarily due to a $31 million decrease in ACMP merger and transition related costs, as well as the impact of various other individually insignificant items, partially offset by a $17 million increase in costs related to our evaluation of strategic alternatives.

2015 vs. 2014

Modified EBITDA decreased significantly as the results from the businesses acquired with our acquisition of ACMP are presented within Williams Partners for periods subsequent to the July 1, 2014, acquisition. Other included the proportional Modified EBITDA of $104 million of our former equity-method investment in ACMP for the first half of 2014, which was partially offset by $19 million associated with our share of compensation costs triggered by the ACMP Acquisition recognized in July 2014. Modified EBITDA also decreased by $30 million related to costs incurred in 2015 related to evaluating our strategic alternatives and the Merger Agreement with Energy Transfer, as well as $24 million of higher costs associated with integration and re-alignment of resources following the ACMP acquisition and merger. These decreases are partially offset by a $9 million contingency gain settlement recognized in fourth quarter 2015.

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2016, we continued to focus upon growth in our businesses through disciplined investment and reducing our costs and funding needs. Examples of this activity included:


•	Expansion of WPZ’s interstate natural gas pipeline system through projects such as Rock Springs to meet the demand of growth markets;


•	Completion of WPZ’s Gulfstar One expansion project to provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico;


•	WPZ’s restructuring of contracts in the Barnett Shale and Mid-Continent region,which included cash payments to WPZ of $820 million;


•	Sale of our Canadian operations (see Note 3 – Divestiture of Notes to Consolidated Financial Statements).

Outlook

Fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, dividends and distributions, debt service payments, and tax payments, while maintaining a sufficient level of liquidity. In particular, as previously discussed in Company Outlook, our expected growth capital and investment expenditures total approximately $2.1 billion to $2.8 billion in 2017. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We retain the flexibility to adjust planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

In January 2017, WPZ announced that it will redeem all of its $750 million 6.125 percent senior notes due 2022 on February 23, 2017. In addition, we expect after-tax proceeds in excess of $2 billion from planned asset monetizations of Geismar and other select assets during 2017, which we expect Williams Partners to use for additional debt reduction and to fund capital and investment expenditures.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2017. Our internal and external sources of consolidated liquidity to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions, and tax payments include:


•	Cash and cash equivalents on hand;


•	Cash generated from operations;


•	Distributions from WPZ;


•	Distributions from our equity-method investees based on our level of ownership;


•	Use of our credit facility;


•	Cash proceeds from issuances of debt and/or equity securities.

WPZ is expected to fund its cash needs through its cash flows from operations and its credit facility and/or commercial paper program, as well as proceeds from planned asset monetizations as previously mentioned. WPZ also established a distribution reinvestment program (DRIP) in the third quarter of 2016.

We previously announced that we intended to reinvest approximately $1.2 billion into WPZ in 2017 via the DRIP, funded primarily by our reduced quarterly cash dividend which would have allowed us to annually retain approximately $1.3 billion for reinvestment. As part of the Financial Repositioning announced in January 2017, we discontinued our participation in the DRIP and expect to increase our regular quarterly cash dividend to $0.30 for the dividend to be paid in March 2017. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.)

We anticipate our more significant uses of cash to be:


•	Working capital requirements;


•	Maintenance and expansion capital and investment expenditures;


•	Interest on our long-term debt;


•	Repayment of current debt maturities, and additional reductions in WPZ’s debt with funds received as part of the Financial Repositioning;


•	Investment in WPZ as part of the Financial Repositioning (see Note 15 – Stockholders' Equity of Notes to Consolidated Financial Statements);


•	Quarterly dividends to our shareholders.

Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.

As of December 31, 2016, we had a working capital deficit (current liabilities, inclusive of $785 million in Long-term debt due within one year, in excess of current assets) of $1.487 billion. Our available liquidity is as follows:



	December 31, 2016
Available Liquidity	WPZ		WMB		Total
	(Millions)
Cash and cash equivalents	$	145	$	25	$	170
Capacity available under our $1.5 billion credit facility (1)			725		725
Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2)	3,407				3,407
	$	3,552	$	750	$</